New base energy news 01 april 2019 issue no 1236 by khaled al awadi

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NewBase Energy News 01 April 2019 - Issue No. 1236 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 petrol price rise in April 9%, following Internal prices moves
The National + NewBase
Motorists in the UAE will pay more at the pumps in April after the new prices were announced by
the fuel price committee.
Here's the breakdown:
• Super 98: up 19 fils to Dh2.23 per litre (up 9.85 per cent)
• Special 95: up 19 fils to Dh2.11 per litre (up 9.89 per cent)
• Diesel: up 8 fils to Dh2.49 per litre (up 3.3 per cent)
Fuel prices in the UAE were liberalised in August 2015, so they now move with the market. The
price for Special 95 was under Dh2 a litre earlier this year, but motorists have been paying 4 per
cent more in March than February and April's rise will be the biggest so far this year.
Oil prices are up about 30 per cent this quarter after Opec and its allies embarked on a mission to
curtail global output, while American sanctions on Iran and Venezuela have also supported higher
prices. Demand is less certain, with US and European indicators pointing to slowing economies and
Washington and Beijing resuming high-level talks this week in a bid to defuse their ongoing trade
dispute.
Brent for May settlement fell 73 cents to $67.10 on the London-based ICE Futures Europe exchange
this morning, while West Texas Intermediate dropped 79 cents, or 1.33 per cent, to $58.62 on the
New York Mercantile Exchange.

UAE: Adnoc awards Indian consortium exploration rights
The for onshore block , source: WAM + The National.
The agreements were signed by Dr Sultan Al Jaber, UAE Minister of State and Adnoc Group CEO,
Duraiswamy Rajkumar, Chairman and Managing Director of Bharat Petroleum Corporation, and
Sanjiv Singh, Chairman of Indian Oil Corporation. Courtesy Adnoc
Abu Dhabi National Oil Company awarded exploration rights to a consortium of two Indian
companies for Dh626 million for an onshore block, as part of its first licensing round. The two Indian
state-backed companies will appraise and possibly develop the existing discoveries in Abu Dhabi's
western region
Bharat Petroleum Corporation and Indian Oil Corporation were awarded 100 per cent interest in the
exploration phase to appraise undeveloped fields around Abu Dhabi’s western region of Ruwais,
Adnoc said on Monday.
The Indian consortium will have the opportunity to develop the existing discoveries, with Adnoc
retaining a 60 per cent stake during the production phase.
“The consortium of Bharat Petroleum Corporation and Indian Oil Corporation, both of whom Adnoc
already partners with offshore, was selected after a very competitive bid round,” Dr Sultan Al Jaber,
Adnoc Group chief executive and UAE Minister of State said.
The award to the Indian consortium concludes Adnoc’s first-ever licensing round, which saw five of
the six blocks tendered picked up by Italy’s Eni, Thailand’s PTT Exploration and Production Public
Company, Occidental of the US and Japan’s Inpex. Onshore Block 2, which had been part of the
tendered concessions is currently being appraised for “unconventional potential” before the
company considers further award decisions, an Adnoc spokesman told The National.

The sale of exploration stakes to the Indian consortium is another indication of the Abu Dhabi
company’s increasing engagement with its consumer base in Asia. Adnoc last year awarded a
consortium of Indian energy companies led by ONGC Videsh a 10 per cent interest in the offshore
Lower Zakum block, following the split and reallocation of its Adma-Opco concessions.
Indian energy companies, which
have until recently not had any
presence in in the Middle East, are
being increasingly wooed by state
companies such as Adnoc, said
Amit Bhandari, senior fellow,
energy and environment with
Mumbai-based think tank Gateway
House.
“Oil demand from the traditional
markets (US, Europe and Japan) is
declining, while China’s oil demand
seems to be plateauing," he said.
"Moreover, the US is also likely to
become a hydrocarbon exporter.
India is likely to account for a large
share of growth in the global oil
demand over the next 20 years."
State-backed firms such as Bharat
Petroleum and Indian Oil
Corporation run a lucrative and strategic network of refineries and fuel distribution outlets in India
as well. "Having them as investors in its upstream assets should result in improved market access
for Adnoc,” added Mr Bhandari.
Adnoc also parks strategic crude reserves in the southern Indian city of Mangalore and is looking
to develop a $44 billion integrated refinery on the country’s western coast in partnership with Saudi
Aramco.
These moves while helping to lock-in long-term market share for the national oil company also allow
for a consuming nation such as India to hedge against high oil prices. Countries such as India and
China recently formed an ‘Asian buyers’ club’ to negotiate for better pricing and mitigate the effects
of highly volatile oil prices.
"Such investments therefore help cushion the impact of high energy prices for the Indian
government, which has to provide subsidies to protect the most vulnerable consumers,” said Mr
Bhandari.
Adnoc meanwhile is likely to offer a second licensing round this year. The company announced in
November discovery of deposits equivalent to a 1 per cent increase to existing oil reserves and a
7.1 per cent addition to proven gas reserves.
The national oil company is widely expected to “continue as they have been progressing,” according
to Tom Quinn, senior research analyst for Middle East at Wood Mackenzie. "They’ve managed to
get a good mix of companies, international companies and Asian companies in terms of market
size," he said. "They also managed to get some pretty big participation bonuses paid by these
companies and having that capital upfront allows them to invest in capacity building projects and
other projects."

Adnoc Drilling targets business outside the UAE amid local capacity ramp-up
Adnoc aims to boost domestic conventional wells drilling by 40% by 2025
Abu Dhabi National Oil Company plans to target drilling outside the UAE as well as boost its local
drilling of conventional resources by 40 per cent by 2025, amid an increase in domestic production
capacity to 4 million barrels per day by 2020.
Adnoc Drilling, the sole rig provider for its parent company, will undertake the local drilling activity
with the help of US oil services company Baker Hughes, a GE company that paid $550 million for a
5 per cent stake in the Adnoc subsidiary last year. Adnoc Drilling has also completed the first “fully
integrated drilling services” well in the onshore Al Dabbyia field.
Integrated drilling services combine the business of well drilling with a wide range of other
complementary services that are necessary to bring the well to the production phase.
“The well was the first to be drilled in a fully integrated way – delivered to Drilling’s client, Adnoc
Onshore, which is helping to enable and support the growth and development of Adnoc Drilling as
the company targets new business opportunities in the UAE and beyond,” Adnoc said on Sunday.
Adnoc is ramping up its oil production capacity to 4 million bpd by 2020 and 5 million bpd by 2030
with the help of international oil companies, which have been awarded stakes in various oil and
gasfields. The company is also seeking to extract more value from its operations, which include an
expanding petrochemicals and refining portfolio.
“In partnership with BHGE, Adnoc Drilling will generate predictable, long-term revenue streams and
growth in the market,” said Abdulmunim Al Kindy, Adnoc's upstream executive director.
“By leveraging a complete range of drilling services, the company will also enhance its operational
performance in line with Adnoc’s 2030 smart growth strategy, which seeks to increase its crude oil
and gas production capacity and optimise costs and efficiencies to create a more profitable
upstream business.”
Baker Hughes’ acquisition of a 5 per cent stake in Adnoc Drilling in October valued the company at
$11 billion.

Saudi-led group offers lowest price to build gas pipeline in Bulgaria
Reuters + Zawyah - By Tsvetelia Tsolova, Reuters News
A consortium of Saudi Arabia's Arkad Engineering and a Milan-based Arkad-ABB joint venture has
filed the lowest bid to build a pipeline that will carry Russian natural gas across Bulgaria, state
network operator Bulgartransgaz said on Friday.
Bulgaria is rushing to build the 474-km (294-mile) pipeline to link its southern border with Turkey to
its western border with Serbia, aiming to secure a link to the Russia-backed TurkStream twin
pipeline to Serbia and Hungary.
The Saudi-led group offered to construct the pipeline by the end of 2020 for 1.1 billion euros ($1.2
billion). Its alternative offer, to build it in eight months, stood at 1.29 billion euros, Bulgartransgaz
said upon offering the bids. Three groups filed offers for the gas link earlier this month.
A consortium including Italian energy contractor Bonatti, German construction company Max
Streicher and a Luxembourg-registered firm owned by Russia's TMK TRMK.MM , offered to build
the gas link for 2.4 billion euros by the year-end, or for 1.69 billion euros by the end of 2020.
Bulgartransgaz said the third bidder, comprised of companies that are part of Hungary's oil and gas
group MOL, did not meet the tender requirements.
"We will look carefully into the offers and will come up with a decision early next week," said Vladimir
Malinov, Bulgartransgaz chief executive, adding that the lowest offer was within its estimated cost.
Russia, which is building TurkStream to bypass Ukraine, has said it would need guarantees from
the European Union that Brussels would not oppose extending one of the legs of the 15.75 billion
cubic metre pipeline via Bulgaria.
Bulgartransgaz plans to provide an advance payment of 250 million euros to the winner and make
instalments for the remaining costs under a 10-year payment plan. Both bidders have agreed to
take re-scheduled payment, with the Saudi tie-up offering a price increase of 4 percent and the
group led by Bonatti offering a top-up ranging between 7 and 9 percent. ($1 = 1.7420 leva).

Saudi Aramco world's biggest oil producer in 2018: Fitch Ratings
Reuters - Reporting by Henning Gloystein; editing by Darren Schuettler
Saudi Aramco was by far the world’s biggest oil producer ahead of regional peers like Abu Dhabi
National Oil Company (ADNOC) and listed oil majors Royal Dutch Shell, Total and BP, ratings
agency Fitch said on Monday.
“Saudi Aramco is the largest oil producer globally by volume... In 2018 its liquids production and its
total hydrocarbon production averaged 11.6 million and 13.6 million barrels of oil equivalent per day,
respectively, well ahead of the upstream output of global and regional integrated producers such as
ADNOC, Shell, Total and BP,” Fitch said.
Fitch said state-owned Aramco “is less integrated into natural gas and downstream than some of
its international peers, such as Shell and Total, which makes it more exposed to oil prices although
this is mitigated by low cost of production, its downstream expansion strategy and, the acquisition
of SABIC.”
Saudi Aramco last week said it would buy a 70 percent stake in Saudi Basic Industries Corp (SABIC)
from the kingdom’s wealth fund for $69.1 billion in one of the biggest deals in the global chemical
industry.
The rating agency said it put Saudi Aramco’s “standalone credit profile (at) ‘AA+’”, adding that this
“rating is capped by that of Saudi Arabia in view of strong linkage between the state and the
sovereign.”

Saudi Aramco was the world’s most profitable company in 2018, according to an extract
of the oil producer’s accounts published by Moody’s Investors Service. The company is
preparing to raise debt in part to pay for the acquisition of a majority stake in domestic
petrochemical group Sabic worth about $69 billion. Aramco will mostly use cash to pay
for the purchase over the next three years.

Oman: FEED award for $8bn Duqm petchem project soon
Oman Observer - Conrad Prabhu
An award is due to be announced shortly for the Front End Engineering Design (FEED) of a giant
petrochemical complex planned for implementation downstream of the Duqm Refinery project in
Oman’s Al Wusta Governorate, according to a key project official.
Dr Salim Saif al Huthaili, CEO of Duqm Refinery & Petrochemical Industries Company LLC
(DRPIC), said the FEED package — marking a key phase
in the implementation of the ambitious project — will be
awarded as soon as the company secures the concurrence
of its principal shareholders represented by Oman Oil &
Orpic Group and Kuwait Petroleum International.
“We are in the final stages of reviewing the final scope of
the project before we proceed with the FEED,” said Dr Al
Huthaili. “We are almost ready to award it, but final
approval from the shareholders both from the Omani and
Kuwaiti sides is pending.”
The mammoth complex, which promises to entrench Oman’s reputation as a global petrochemicals
heavyweight, will further anchor Duqm’s transformation into a maritime and industrial hub, while
powering Oman’s socioeconomic development well in the future.
Speaking at a media briefing hosted by the Ministry of Oil and Gas recently, Dr Al Huthaili said the
capital cost of the petrochemical complex will surpass the estimated $7 billion investment in Duqm
Refinery, underscoring the world-scale size of the petchem project.
“In terms of the projected investment and capital spend, we are expecting it to be between $8 billion
and north of $8 billion. We are probably looking at one of the world’s biggest petrochemical crackers
in the magnitude of something like 1.6 million tonnes of ethylene production per year, besides
propylene and other molecules, and downstream activities as well.”
Giving a tentative timeline for the implementation of the mammoth scheme, the CEO stated: “Once
the (FEED package is awarded), we expect it to take about 18 months before a (Final Investment
Decision) on the project is taken to move forward with the construction.
Typically, with a mega project like this, construction takes about four years — so 2025-26 is the
expected timeline for delivering the project.” Construction work on Duqm Refinery itself — one of
several mega developments that promise to anchor Duqm’s growth into an economic dynamo — is
progressing per schedule, said Dr Al Huthaili.
“This is a very interesting project for Oman, and an anchor project as well. In fact, after achieving
financial close at the end of last year, HE Yahya al Jabri (Chairman of the SEZ Authority of Duqm),
was saying that the amount of investment coming to Duqm has been immense. So this project is
sparking a lot of interest in Duqm.”
As a world-class grassroots refinery based on advanced technology, the 230,000 barrels per day
capacity Duqm Refinery will produce an array of clean products that comply with global standards
for quality and safety. The refinery will also bolster the energy industry of Oman by strengthening
the supply and production of Diesel, Jet fuel, Naphtha, LPG, Sulfur and Pet coke as its primary
products.

US:Tight oil development to drive future U.S. crude oil production
Source: U.S. Energy Information Administration, Annual Energy Outlook 2019
EIA’s Annual Energy Outlook 2019 (AEO2019) Reference case projects that U.S. tight oil
production, which became the more common form of oil production in 2015, will continue to increase
through 2030, ultimately reaching more than 10 million barrels per day (b/d) in the early 2030s.
Tight oil production reached 6.5 million b/d in the United States in 2018, accounting for 61% of total
U.S. production. EIA projects further U.S. tight oil production growth as the industry continues to
improve drilling efficiencies and reduce costs, which makes developing tight oil resources less
sensitive to oil prices than in the past.
Recent growth in U.S. crude oil production has been driven by the development of tight oil
resources, primarily in the Permian Basin in western Texas and eastern New Mexico. Three major
tight oil plays in the Permian Basin—the Spraberry, Bone Spring, and Wolfcamp—accounted for
41% of U.S. tight oil production in 2018.

In the AEO2019 Reference case, approximately half of cumulative tight oil production through 2050
is expected to come from these three plays. The Bakken and Eagle Ford plays also remain major
contributors to U.S. tight oil supply through 2050, accounting for 19% and 17% of cumulative tight
oil production, respectively.
However, future growth of domestic tight oil production depends on a variety of factors, including
the quality of resources, technology and operational improvements that increase productivity and
reduce costs, and market prices. AEO2019 includes several sensitivity cases that incorporate
different assumptions regarding oil prices, technological improvement, and resource recoverability.
The High Oil and Gas Resource and Technology case uses more optimistic technology and
resource assumptions than in the Reference case. In this case, U.S. tight oil production increases
through the mid-2040s, as higher productivity reduces development and production costs, spurring
additional resource development.
Tight oil production slowly decreases toward the end of the projection period as drilling moves to
less productive areas. Total U.S. oil production in 2050 in this case is nearly 19 million b/d, much
higher than the Reference case level of about 12 million b/d.
In the Low Oil and Gas Resource and Technology case, which uses more pessimistic technology
and resource assumptions than the Reference case, tight oil production still increases from its
current level through the early 2020s before gradually declining through 2050. Total U.S. oil
production in 2050 in this case falls to about 8 million b/d.
In these two sensitivity cases, technology and resource assumptions are modified, but the world oil
prices are assumed to be the same as in the Reference case. The AEO2019 also contains two

cases that assume higher and lower world oil prices under the same resource and technology
assumptions as in the Reference case.
In the High Oil Price case, West Texas Intermediate spot prices rise rapidly from $68 per barrel in
2018 to more than $100 per barrel in 2019 and then gradually increase to $208 per barrel by 2050
(in 2018 dollars). As a result, total domestic crude oil production increases to almost 18 million b/d
by 2024 before declining to 13 million b/d in 2050.
This high oil price assumption results in the fastest near-term increase in tight oil production as
higher prices speed up the pace of drilling. After the mid-2020s, tight oil production declines through
2050 as drilling moves to less productive areas.
In the Low Oil Price case, sustained low oil prices, averaging less than $50 per barrel through 2050,
cause total domestic production to increase more slowly, from 10.9 million b/d in 2018 to nearly 13
million b/d in 2022, before gradually declining through the rest of the projection period. Tight oil
production averages close to 6 million b/d in 2050, accounting for 69% of total domestic oil
production.

NewBase 01 April 2019 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices push higher as supply worries drive gains
Reuters + NewBase
Oil prices rose on Monday, adding to gains in the first quarter when the major benchmarks posted
their biggest increases in nearly a decade, as concerns about supplies outweigh fears of a slowing
global economy.
Brent crude for June delivery was up by 90 cents, or 1.33 percent, at $68.48 a barrel by 04.14 GMT,
having risen 27 percent in the first quarter.
U.S. West Texas Intermediate (WTI) futures rose 49 cents, or 0.81 percent, to $60.63 barrel, after
posting a rise of 32 percent in the January-March period.
U.S. sanctions on Iran and Venezuela along with supply cuts by members of the Organization of
the Petroleum Exporting Countries(OPEC) and other major producers have helped support prices
this year, overshadowing concerns about global growth and the U.S.-China trade war.
Oil price special
coverage

However, future gains will be limited by potential softness in the global economy as well as the
ability of U.S. oil producers to ramp up production when prices spike, said Phin Ziebell, senior
economist at National Australia Bank in Sydney.
"It's tough to see a really big rally from here," he said.
Still, analysts have turned cautiously optimistic on crude oil prices this year, a Reuters poll showed
on Friday.
U.S. production has also steadied, with the U.S. government reporting on Friday that domestic
output in the world's top crude producer edged lower in January to 11.9 million bpd.
U.S. energy firms last week reduced the number of oil rigs operating to the lowest level in nearly a
year, cutting the most rigs in a quarter in three years, Baker Hughes energy services firm said.
Sigal Mandelker, U.S. under-secretary of the Treasury for Terrorism and Financial Intelligence, told
reporters in Singapore on Friday that the United States had placed further "intense pressure" on
Iran.
U.S. officials are keen to ensure see that Malaysia, Singapore and others are fully aware of illicit
Iranian oil shipments and the tactics Iran uses to evade sanctions, Mandelker said.
The U.S. has also instructed oil trading houses and refiners to further cut dealings with Venezuela
or face sanctions themselves, even if the trades are not prohibited by published U.S. sanctions,
three sources familiar with the matter said.
A deal between OPEC and allies such as Russia to cut output by around 1.2 million barrels per day,
which officially started in January, has also supported prices.

NewBase Special Coverage
News Agencies News Release 06 March 2019
U.S. energy-related CO2 emissions will remain near current
level through 2050,,,U.S. EIA, Monthly Energy Review, Annual Energy Outlook 2019 Reference case + EIA
Carbon dioxide emissions from U.S. energy consumption will remain near current levels through
2050, according to projections in EIA’s Annual Energy Outlook 2019. The AEO2019 Reference
case, which reflects no changes to current laws and regulations and extends current trends in
technology, projects that U.S. energy-related carbon dioxide (CO2) emissions will be 5,019 million
metric tons in 2050, or 4% below their 2018 value, as emissions associated with coal and petroleum
consumption fall and emissions from natural gas consumption rise.
Energy-related CO2 emissions generally follow energy consumption trends. In the United States,
emissions associated with the consumption of petroleum fuels—motor gasoline, distillate, jet fuel,
and more—have consistently made up the largest portion of CO2 emissions. In 2018, the
transportation sector’s consumption accounted for 78% of U.S. CO2 emissions from petroleum and
more than one-third of all U.S. energy-related CO2 emissions. Petroleum emissions from other
sectors have fallen in recent years as equipment and processes that use petroleum fuels have been
replaced by those using other fuels, in particular, natural gas.
In the transportation sector, consumption and emissions trends in the past have been driven by
changes in travel demand, fuel prices, and fuel economy regulations. In EIA’s AEO2019 Reference
case projection, current fuel economy standards stop requiring additional efficiency improvements
in 2025 for light-duty vehicles and in 2027 for heavy-duty vehicles, reflecting existing regulations.
As travel demand continues to rise, transportation consumption and emissions increase.

Natural gas is the least carbon-intensive fossil fuel, and for decades natural gas made up the
smallest portion of U.S. energy-related CO2 emissions. However, in 2015, natural gas emissions
surpassed coal emissions, and the AEO2019 Reference case projects that natural gas CO2
emissions will continue increasing as natural gas use increases. The U.S. electric power sector—
now the largest consuming sector for natural gas—has added generating capacity from natural
gas in recent years and has used those power plants more often. Natural gas surpassed coal to
become the most prevalent fuel used to generate electricity in the United States in 2016.
Other sectors have also increased their consumption of natural gas. By the mid-2020s, EIA projects
that the industrial sector will again become the largest consumer of natural gas, using natural gas
as a feedstock in chemical industries, as lease and plant fuel, for industrial heat and power
applications, and for liquefied natural gas production. The residential and commercial sectors are
also expected to continue using more natural gas. For instance, EIA projects that natural gas
furnaces and boilers will be used in 55% of U.S. homes in 2050, an increase from their 49% share
in 2018.

U.S. natural gas plant liquid production continues to hit record highs
Since 2012, when horizontal drilling and hydraulic fracturing techniques became more common,
U.S. production of natural gas plant liquids (NGPL) has significantly increased, averaging 4.3 million
barrels per day (b/d) in 2018, up from 2.5 million b/d in 2012. Nearly three-quarters of U.S. NGPL
production is concentrated within six producing regions.
The Permian, Eagle Ford, and Appalachian regions made up more than half of all U.S. NGPL
production in 2017. An additional one-quarter of NGPL production was located in three other
regions—the Anadarko Basin in western Oklahoma and Texas; the Bakken play in North Dakota
and eastern Montana; and the Green River, Piceance, Uinta, and Paradox Basins in the Western
Rockies region of Utah, Wyoming, and Colorado.
NGPL production has generally increased across all regions since 2012 as production of natural
gas has grown. The largest increase has been in the Northern Appalachian region, where production

increased from 43 thousand b/d in 2012 to 512 thousand b/d in 2017. NGPL production has doubled
in both the Permian Basin in western Texas and southeastern New Mexico and the Eagle Ford play
in southern Texas from 2012 to 2017. NGPL production in the Bakken play more than tripled.
Natural gas requires processing before entering interstate natural gas pipelines. The raw, or wet,
natural gas includes methane—the primary component of delivered natural gas—as well as NGPLs
such as ethane, propane, normal butane, isobutane, and natural gasoline. Once impurities such as
water, hydrogen sulfide, and carbon dioxide are removed from the wet natural gas, the mixed
NGPLs are transported for further processing at fractionation plants that separate the NGPLs into
distinct commodities.
In most production regions, NGPLs must be shipped by pipeline to fractionation centers, such as
Mont Belvieu, Texas, and Conway, Kansas, both of which act as storage, distribution, and pricing
hubs for NGPLs. Northern Appalachia is one of the few areas that fractionate NGPLs in the same
region where they are produced. In December 2018, the U.S. Department of Energy published a
report highlighting the development potential for a new ethane hub in the Appalachian region.
NGPLs typically sell at higher values than methane on a heat-content basis because they are priced
against crude oil-derived fuels. The yield of these liquid products can vary depending on
the constitution of the raw natural gas, the technology used to extract NGPLs at processing plants,
and the NGPL market prices and demand, especially for ethane. The domestic and international
markets for individual NGPL products have grown with the growing U.S. NGPL production, as these
liquids are used for feedstock in manufacturing plastics and resins.
In 2017, the U.S. volume-weighted average yield of NGPLs from raw natural gas was 84 barrels per
million cubic feet (b/MMcf) of processed natural gas. The Bakken generates the highest NGPL yield,
or richest natural gas, with an average of 143 b/MMcf. Raw natural gas from the Permian and Eagle
Ford yields 95 b/MMcf and 107 b/MMcf, respectively. At 31 b/MMcf, the Western Rockies raw
natural gas has the lowest NGPL yield. Producers will generally prioritize production from richer
formations to maximize NGPL yields unless they lack the infrastructure to process wet gas and
transport the liquids to market.

U.S. nuclear electricity generation in 2018 surpassed its previous peak
Electricity generation from U.S. nuclear power plants totaled 807.1 million megawatthours (MWh)
in 2018, slightly more than the previous peak of 807.0 million MWh in 2010, based on preliminary
annual data. Although several nuclear power plants have closed since 2010, a combination of added
capacity through uprates and shorter refueling and maintenance cycles allowed the remaining
nuclear power plants to produce more electricity. In the near future, however, EIA expects that U.S.
nuclear power output will decline.
Between 2010 and 2018, only one new nuclear power plant came online in the United States.
The Tennessee Valley Authority's (TVA) Watts Bar Unit 2 nuclear power reactor came online in the
fall of 2016, providing 1.2 gigawatts (GW) of additional power. Seven plants with a combined
capacity of 5.3 GW had retired since 2013. As of the beginning of 2019, the United States had 98
nuclear power reactors at 60 plants, but two plants—Pilgrim, Massachusetts’s only nuclear plant,
and Three Mile Island in Pennsylvania—are expected to retire later this year, based on announced
retirements.
Despite changes in capacity from plants coming online or retiring, the U.S. nuclear power fleet
maintained electricity generation near 800 million MWh for over a decade for several reasons.
Several plants commissioned uprates, which involves modifying the plant to increase its generating
capacity. EIA recorded 2.0 GW of thermal power uprates between 2010 and 2018, nearly the
equivalent of adding two new reactors similar to Watts Bar Unit 2.
Nuclear power plants have also shortened the time they are out of operation for refueling or
maintenance. Nearly all of the recent reduction in outage duration is attributed to shorter outages
for refueling operations. In 2018, the average nuclear reactor outage was about 25 days. Nuclear
power plants typically refuel every 18 to 24 months, so some of the annual fluctuations in nuclear
output are largely attributable to how maintenance cycles align across the fleet.

The combination of uprates, shorter outage durations, and balance-of-plant thermal efficiency
improvements led the U.S. nuclear power fleet in 2018 to see its highest capacity factor on record,
at 92.6%.
The 2018 peak level of U.S. nuclear generation is not likely to be surpassed in the coming decades.
Based on project information reported to EIA, only two new nuclear reactors are scheduled to come
online in the near future. Georgia's Vogtle Units 3 and 4, which are planning to come online in 2021
and 2022, respectively, would provide 2.2 GW of additional power. However, this new capacity will
not offset the capacity that is expected to retire in the next seven years, based on announced
retirements. Two plants will retire later this year, three more in 2020, and four more in 2021. By
2025, U.S. nuclear capacity will fall by 10.5 GW from the closings of twelve reactors.
Opportunities for further uprates, which had offset the loss of nuclear electricity capacity in recent
years, are shrinking. According to the NRC, only 60 megawatts (MW) of thermal uprate applications
are anticipated through 2020. Current market conditions—the combination of relatively low
wholesale electricity prices and flat demand growth—do not provide the financial incentives plant
owners require to invest in improvements that would increase output from the existing fleet.

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Khaled Al Awadi is a UAE National with a total of 28 years of experience in
the Oil & Gas sector. Currently working as Technical Affairs Specialist for
Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy
consultation for the GCC area via Hawk Energy Service as a UAE operations
base , Most of the experience were spent as the Gas Operations Manager in
Emarat , responsible for Emarat Gas Pipeline Network Facility & gas
compressor stations . Through the years, he has developed great experiences
in the designing & constructing of gas pipelines, gas metering & regulating
stations and in the engineering of supply routes. Many years were spent drafting, & compiling gas
transportation, operation & maintenance agreements along with many MOUs for the local
authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE
and Energy program broadcasted internationally, via GCC leading satellite Channels.
NewBase : For discussion or further details on the news above you may contact us on +971504822502 , Dubai , UAE
NewBase 2019 K. Al Awadi

New base energy news 01 april 2019 issue no 1236 by khaled al awadi

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New base energy news 01 april 2019 issue no 1236 by khaled al awadi