New base 04 december 2017 energy news issue 1108 by khaled al awadi

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NewBase Energy News 04 December 2017 - Issue No. 1108 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 energy minister named Opec summit president, 1st jan.2018
WAM .. UAE's Minister of Energy and Industry Suhail bin Mohammed Faraj Faris Al Mazrouei has
been elected as president of the Organisation of the Petroleum Exporting Countries (Opec)
Conference for one year, with effect from January 1.
This came during the
173rd meeting of the
Opec conference held
here on Thursday
under the
chairmanship of its
current President
Khalid A. Al-Falih,
Minister of Energy,
Industry and Mineral
Resources of Saudi
Arabia, reported state
news agency Wam. Major General Manuel Quevedo, the Minister of Petroleum and Energy of the
Bolivarian Republic of Venezuela, has been elected as alternate president, for the same period, it
stated.
The meeting was a crucial one where Opec and non-Opec producers agreed to extend oil output
cuts until the end of 2018. The deal to cut oil output by 1.8 million barrels a day was adopted by
the 14-member Opec cartel, Russia and nine other global producers. The conference took note of
oil market developments since it last met in Vienna on May 25, 2017, and reviewed the oil market
outlook for the remainder of 2017 and 2018.
It observed that global economic growth forecasts had improved since May, with expectations for
both 2017 and 2018 now at 3.7 per cent, said the report. In addition, global oil demand has been
robust with upward revisions since May, with oil demand growth now standing above 1.5 mbd for
both 2017 and 2018.
It is also evident that the market rebalancing has gathered pace since May, with the OECD stock
overhang falling to around 140 mb above the five-year average for October, a drop of almost 140
mb since May, reported Wam. Moreover, crude in floating storage has also fallen significantly over
this period. Despite this success, the conference reiterated that it was vital that stock levels be
drawn down to normal levels.
In view of the uncertainties associated mainly with supply and, to some extent, demand growth, it
is intended that in June 2018, the opportunity for further adjustment actions will be considered
based on prevailing market conditions and the progress achieved towards rebalancing of the oil
market at that time, it added.

OPEC Can Drain Some Oil Barrels With a Calculator
By Liam Denning
OPEC and its associates, which extended their supply cuts on Thursday, are chasing a
particularly elusive quarry known as the five-year average of commercial oil inventories in the
OECD countries.
This stockpile of oil held by companies (rather than government-controlled strategic stocks) is the
most visible indicator of the glut weighing on oil prices and OPEC's progress in draining it.
The Blob
The oil glut began building in earnest in 2015 as OPEC first refused to cut supply to support
prices, and draining it is a slow process
Source: International Energy Agency, Bloomberg Gadfly analysis
Note: Data for October 2017 are estimated, based on preliminary stock movements in the U.S., Europe and Japan.
At the start of the 2017, stocks were 278 million barrels above the five-year average for that
month, according to OPEC. As of October, the excess had dropped to 140 million, the group said
Thursday. It aims to close that next year, with a review planned for June.
The good news for OPEC is that the average itself will do some of the job.
I wrote here about how the build-up of the oil glut meant five-year moving averages of U.S.
inventories were also rising. Like a big meal moving through a python, a sudden increase in
stocks will cause a bulge in the moving average for several years.
The same is happening with OECD inventories. Based on OPEC's published data, the implied
five-year average stockpile for June 2018 -- meaning the average level for that month in the years
2013 through 2017 -- is 2.853 billion barrels. The implied average for October 2017 is 2.818
billion.

In other words, the average will rise 35 million barrels by the time of the next Vienna show. That
means one out of every four barrels OPEC needs to disappear in order to hit its target will be
drained not by demand or supply -- just math.
Using the International Energy Agency's figures, and based on preliminary data about stock draws
in the U.S., Europe and Japan, it looks like inventories in October were 136 million barrels above
the five-year average. Between then and next June, movements in the IEA's average should
reduce that by almost 41 million barrels, or 30 percent of the target.
Given how stubborn inventories have proven to be, with OPEC having just extended its initial six-
month cut to a potential 24 months, the group will welcome any help, however abstract.
It's still a tough slog, though. While demand has been rising, OECD inventories as of September
were still adequate to cover more than 62 days of forward demand, versus the mid-to-high 50s
level that prevailed before the crash.
Production from outside of OPEC is expected to continue rising into 2018, outpacing demand
growth. This isn't just about U.S. tight oil -- although any effort by OPEC to support prices can't
help but do favors for frackers. Earlier this week, Exxon Mobil Corp. started production from
its Hebron project, off the coast of Newfoundland, part of a surge in Canadian output expected in
2018. Brazil also should see gains next year.
Estimates vary widely. The chart below shows expected growth in non-OPEC supply less growth
in global demand, quarter over quarter, as forecast by the IEA, the U.S. Energy Information
Administration, and OPEC:
Game Of Two Halves
On balance, non-OPEC supply gains look adequate to cover demand growth through the first half
of 2018
Source: IEA, EIA, OPEC
Note: Growth in non-OPEC liquids supply less growth in global liquids demand, quarter over quarter.

There's a clear inflection point after the second quarter. OPEC's forecast is clearly the most bullish
for the second half of the year, which also helps explain the need for that review in June.
However, it's worth noting that this rests largely on much more bullish demand forecasts for the
back end of 2018 compared to the IEA and EIA. An even starker difference is that OPEC expects
non-OPEC supply to simply not grow at all between the first and third quarters.
The latter, especially, seems a questionable assumption, especially if OPEC's own cuts keep oil
prices where are they are now. Saudi Arabia's energy minister indicated on Thursday that
enforcement of supply cuts should step up next year and that some struggling members will likely
contribute "involuntary cuts" -- a euphemism for the sort of disaster that is engulfing
Venezuela right now. Still, only time will tell on this front.
One thing that will happen, no matter what, is that the helpful math of the moving average will start
to move the other way. Just as the glut caused the average to bulge, so OPEC's efforts so far to
drain the tanks will start to catch up with the average:
May The Road Rise To Meet You
The five-year average's convergence with actual stocks should peak next summer
Source: International Energy Agency, Bloomberg gadfly analysis
Note: Commercial oil inventories in the OECD countries. Data for October 2017 and October 2018 are estimates based on
preliminary stock moves in the U.S., Europe and Japan.
Of course, OPEC won't mind the average falling away; it will simply provide proof that its cuts
have really had a lasting impact on the glut -- provided, that is, inventories really do keep dropping
through the end of next year.

Saudi Arabia and Russia reach compromise on oil pact: Kemp
Reuters - John Kemp
Ministers from OPEC and their allies have agreed to extend their production pact all the way to the
end of 2018 but with a review in June that will take into account market conditions and progress
toward rebalancing.
The outcome represents a successful compromise between de facto OPEC leader Saudi Arabia
(which wanted to announce an extension throughout 2018) and non-OPEC heavyweight Russia
(which wanted to avoid giving such a long commitment).
SPONSORED
The decision was in line with traders’ expectations and there has been little change in either
outright crude prices or calendar spreads since the decision was announced on Thursday.
As a practical matter, it makes little difference whether the decision is described as a nine-month
extension from the end of March, when the current cuts were scheduled to expire; or a three-
month extension from March to June with the option of extending them until December 2018.
The compromise allows ministers to signal a resolve to do whatever it takes to rebalance the
market (a Saudi priority) while preserving flexibility to adapt to changing market conditions (a
Russian one).
Critically, it recognizes the oil market has already made significant progress toward rebalancing
but also that there is uncertainty about how quickly the process will be completed. Saudi Arabia’s
oil minister Khalid Al-Falih said on Thursday the excess of OECD oil stocks over the five-year
average had already shrunk from 280 million barrels in May to just 140 million in October.

Crude oil in floating storage has fallen by 50 million barrels since June, and products stocks are
already down to their five-year average (“Opening address to the 173rd meeting of the OPEC
conference”, Falih, Nov. 30).
Both Brent and WTI have flipped from contango
into backwardation for the first time since 2014,
Falih noted, indicating the market’s move toward a
more balanced condition. “Market stability has
improved and the sentiment is generally upbeat.
The rebalancing trend has accelerated and
inventories are generally on a declining trend,” Falih
concluded.
Rebalancing is now more than half-way completed,
he said, but the market is moving toward the
seasonally weak, low-demand period through the second quarter of 2018. For Saudi Arabia,
therefore, the emphasis was on maintaining production discipline to get the job finished and avoid
a renewed slump in oil prices. “We must stay the course,” Falih urged his colleagues.
Russia, however, has begun to worry about what comes next once rebalancing has been
achieved.
Brent prices are already trading well near $64 per barrel, the average for the whole of the last
cycle from 1998 to 2016. In real terms, the average Brent price in 2017 will be in line with the
median since 1973.
The Brent spread is now well into the upper half of its full cycle range, and the backwardation is
firmly established, which points to a market that is no longer significantly oversupplied. If OECD
stocks were to decline to the five-year average, the market would almost certainly feel
uncomfortably tight, given the enormous growth in oil consumption since 2012.
Oil prices and calendar spreads would rise further, and the shift could be very rapid. Rising prices
would encourage a sharp increase in drilling and production from the U.S. shale sector. As Falih
acknowledged, the pace of rebalancing has accelerated, which is normal cyclical behavior,
because supply-demand-stocks-prices dynamics in the oil market are highly non-linear.
If OPEC waits before adjusting production until stocks have fallen close to the five-year average
and the market has fully rebalanced, it will risk a spike in both prices and spreads to the upside.
Prices and spreads overshot following both the previous OPEC-led efforts at oil market
rebalancing after the slumps of 1998/99 and 2008/09.
For Saudi Arabia, which needs higher oil revenues to fund its ambitious transformation program,
and higher prices to secure a favorable price for the Aramco share listing, overshooting might not
be a problem.
But Russia needs the extra revenue less and is more worried about losing market share in Europe
and Asia to competition from rising U.S. shale oil exports. The compromise allows both sides to
claim a measure of victory, with Saudi Arabia getting a nine-month extension and Russia
obtaining an explicit commitment to review after three months.
The bottom line is that OPEC and its allies are committed to maintaining current production levels
through the end of June 2018. The pact may be extended until the end of 2018, with or without
modifications, depending on the level of stocks and prices when the review is conducted in the
middle of next year.

Namibia: Pancontinental awarded Block 2713, offshore
Source: Pancontinental Oil & Gas
• Pancontinental has signed a Petroleum Agreement with the Ministry of Mines and Energy of
Namibia (Ministry) and Namibian partners for Block 2713 offshore Namibia.
• Pancontinental is the project Operator, with a 75% interest. Block 2713 is a large, 10,947 km² area
on trend where industry giants Shell, GALP (Portugal) and Total (in 2017) have acquired interests.
It is Pancontinental’s second Block award offshore Namibia.
• The Company has already mapped a number of leads with very large oil volume potential.

• The Block has an initial period of 4 years, and an innovative exploration program is
planned.
• The Petroleum Agreement is subject to standard fiscal terms in Namibia that are considered
excellent by world standards.
• In PEL 37, the Company’s first Namibian project that is operated by Tullow Oil, the joint
venture has recently approved drilling of the Cormorant Prospect in 2018. Pancontinental
will have an effective free carried 20% interest through the well.
Commenting on the new opportunity, Pancontinental CEO John Begg said:
'We are delighted that the Ministry has granted Pancontinental this new area. We believe that
offshore Namibia is one of a select few areas around the world with the potential for large oil
discoveries in modest to deep water that can be profitable at prevailing oil prices, and highly
profitable at better prices.
It is clear from recent activity that some of the world’s pre-eminent oil companies agree with us.
Namibia offers a stable, pragmatic and complementary fiscal regime with the potential for large oil
traps and high quality reservoirs. Our mapping already shows leads in play trends with very large
oil volume potential. So we have taken a majority, 75% operated position in the new project with
cost exposure within our capabilities. Further, we plan to apply our proven skills to bring the oil
potential of this project into an up-to-date context that is attractive to wider industry investment.
The new Licence complements our existing strong position in PEL 37 in Namibia that is operated
by Tullow and where ONGC Videsh and African Energy Corp have also recently invested with us.
The PEL 37 joint venture has committed to drill a well in PEL 37 timed for Q3 next year'.
The New Block
Pancontinental Oil & Gas is pleased to announce that it has signed a Petroleum Agreement ('PA')
over a large exploration area of 10,947 km² in the Orange Basin offshore Namibia. A new
Petroleum Exploration Licence (PEL) will be issued over the area.
About Block 2713
Pancontinental believes that Block 2713 is highly prospective for oil, with high quality mature oil
source rocks and the potential for very large oil traps. Water depths are between 500m and 3,200
m and the area is on trend with the actively explored Total / Impact Oil and Gas deepwater block,
the subject of a farmin by Total in October 2017. The new Pancontinental project area is in a
region where high-capacity oil prospects, such as large turbidites, have been identified.

Pancontinental signed the new PA with the Ministry of Mines and Energy of the Republic of
Namibia alongside Namibian partners Custos Investments (Pty) Ltd (15%) and Namcor, the
National Petroleum Corporation of Namibia (10%). Pancontinental has a 75% interest and is the
project Operator.
Pancontinental’s commitments to Block 2713 for at least the first two years are amply within the
Company’s financial capabilities. The introduction of aligned industry partners will be considered
as the project progresses, in keeping with the Company’s proven strategies and expertise as
evidenced by the structure of the PEL 37 joint venture. The Namibian partners will be carried
through the exploration phase of the Licence.
Exploration activity has already commenced on the new PA area including data acquisition, initial
geological and geophysical mapping and compilation of leads and prospects. Prospective
“fairways” and potential traps covering large areas adjacent to mature oil prone source rocks have
already been identified and will be the subject of ongoing exploration work.
Interests in the new project are: Pancontinental Orange (a wholly owned subsidiary of
Pancontinental Oil & Gas) 75% (Operator); Custos Investments 15%; National Petroleum
Corporation of Namibia (Namcor) 10%
Activity in Pancontinental’s PEL 37
The new award adds to Pancontinental’s activities in PEL 37 further to the north offshore Namibia,
a project it generated in 2011. PEL 37 is operated by Tullow Namibia Limited (subsidiary of Tullow
Oil plc) following a farmin to Pancontinental in 2013. More recently, ONGC Videsh of India and
Africa Energy Corp ('AEC'), a subsidiary of Lundin Group, have invested in the project.
Pancontinental, with an effective 20% interest, will participate in drilling the Cormorant Prospect in
PEL 37 in Q3 2018 under a farmin 'carry' by Tullow Oil.
In September 2017 in PEL 37, Pancontinental reached agreement with AEC for payment of
US$7.7 million to Pancontinental in two stages in return for AEC taking a 33.33% shareholding in
the Pancontinental subsidiary that holds a 30% interest in PEL 37. This means that
Pancontinental and AEC have effective 20% and 10% carried interests respectively in PEL 37.

U.S, Canada & Mexico launch N. Energy info. website
Source: U.S. Energy Information Administration
At the North American Energy Ministerial on November 14, 2017, in Houston, Texas, United
States Secretary of Energy Rick Perry, Canada’s Minister of Natural Resources James Gordon
Carr, and Mexico’s Secretary of Energy Pedro Joaquin Coldwell launched the North American
Cooperation on Energy Information (NACEI) website. The website consolidates energy-related
data, maps, analyses, and references from the three countries in English, Spanish, and French.
Canada and Mexico are key energy trade partners with the United States. The NACEI site’s
overview page shows energy flows among the countries for crude oil, natural gas, and electricity.
In 2016, Canada was the largest source of U.S. crude oil imports, supplying more crude oil to the
United States than all members of the Organization of the Petroleum Exporting Countries (OPEC)
combined.
Mexico was the fourth-largest source of U.S. crude oil imports in 2016, behind Canada, Saudi
Arabia, and Venezuela. Canada was also the top destination for U.S. crude oil exportsin 2016,
receiving 61% of all U.S. crude oil exports.
https://www.nacei.org

Natural gas trade flows among the three countries are also significant: Canada is the largest
source of U.S. natural gas imports—mostly through pipelines that cross the border into states
such as Idaho and Montana. Mexico is the largest destination of U.S. natural gas exports—mostly
through pipeline border crossings in Texas.
Electricity trade with Canada and Mexico, while totaling less than 2% of U.S. consumption, is still
an important part of electricity markets as cross-border transmission connections support regional
electric system reliability. In 2016, the United States imported 73.1 million megawatthours (MWh)
from Canada and 1.5 million MWh from Mexico, while exporting 9.3 million MWh and 2.3 million
MWh to those countries, respectively.
The new NACEI website provides detailed data by energy source and country of origin with
conversion factors, data units, and definitional cross references. An interactive map has multiple
layers showing electric power plants, refineries, natural gas processing plants, and other
components of energy infrastructure in the three countries. Weather-related layers show key
energy infrastructure that could potentially be affected by hurricanes, floods, and other extreme
weather events.
The outlook section is designed to improve coordination and understanding of national energy
outlooks and models of the interrelationships among the three countries as an integrated North
American energy system.
The primary participating agencies in the NACEI initiative include the Department of Natural
Resources, Statistics Canada, and the National Energy Board from Canada; the Secretaría de
Energía, Comisión Reguladora de Energía, Comisión Nacional de Hidrocarburos, Petróleos
Mexicanos, Comisión Federal de Electricidad, Centro Nacional de Control de Gas Natural, Centro
Nacional de Control de Energía, and the Instituto Nacional de Estadística y Geografía from
Mexico; and the U.S. Energy Information Administration and Office of Fossil Energy of the U.S.
Department of Energy and the U.S. Census Bureau from the United States.
The goal of the initiative is to create an institutional framework for consultation and for sharing
publicly available materials to improve energy information and energy outlooks for North America.
Collaboration among the three countries has already improved data quality for some data series.
The current areas of focus include:
• Comparing, validating, and improving respective energy import and export information
• Sharing publicly available geospatial information related to energy infrastructure
• Exchanging views and information on projections of cross-border energy flows
• Harmonizing terminology, concepts, and definitions of energy products

NewBase 04 December 2017 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices fall after US drillers add rigs, after a stable week
Reuters + NewBase
Oil fell on Monday after U.S. shale drillers added more rigs last week, but prices held not far off
their highest since mid-2015, supported by an extension of output cuts agreed last week by OPEC
and other producers.
Drillers in the United States added two oil rigs in the week to Dec. 1, bringing the total count up to
749, the highest since September, energy services firm Baker Hughes said in its closely followed
report late on Friday.
U.S. West Texas Intermediate was down 21 cents, or 0.3 percent, at $58.15 a barrel at 0112
GMT. Brent futures were 22 cents, or 0.4 percent, lower at $63.51 a barrel.
The U.S. rig count, an early indicator of future output, has risen sharply from the 477 rigs that
were active a year ago after energy companies boosted spending plans for 2017.
Drillers were encouraged as crude prices started recovering from a two-year price crash around
the same time the Organization of the Petroleum Exporting Countries (OPEC) and some non-
OPEC producers including Russia agreed to production cuts a year ago.
Oil price special
coverage

On Thursday, producers agreed to extend the output cuts that were due to expire next March until
the end of the year, continuing to restrain production by about 1.8 million barrels per day (bpd).
The latest agreement allows for producers to exit the deal early if the market overheats. Russian
officials had expressed concern that extending the output cuts might encourage rival U.S. shale
firms to pump more crude.
Rising U.S. production has been a persistent thorn in OPEC's side and the rig increased for a
second straight week.
U.S. production rose to 9.5 million bpd in September, its highest monthly output since 9.6 million
bpd in April 2015, according to federal energy data going back to 2005. On an annual basis, U.S.
output peaked at 9.6 million bpd in 1970.

NewBase Special Coverage
News Agencies News Release 04 Dec. 2017
OPEC Just Did American Shale Drillers a Big Favor
Bloomberg + Newbase + eia
OPEC and Russia just gave their most implacable foe, U.S. shale, an early holiday gift.
As corporate boards for American oil explorers prepare to sketch out 2018 drilling budgets,
Thursday’s historic agreement by Saudi Arabia, Russia and other major crude producers to
extend supply caps for another year may prompt directors to spend more on drilling. That’s
because the producer group’s restraint has meant higher prices for U.S. shale drillers, who
haven’t been shy about hiring more rigs or flooding global markets with more cargoes.
After climbing out of a crater dug by the worst oil-market collapse in a generation, North American
explorers probably will boost spending by 20 percent next year, according to an Evercore ISI
survey of industry budget trends. That would follow an estimated 41 percent jump in 2017.
“The North American E&P industry is very itchy to spend more capital dollars,” said James West,
an Evercore analyst who’s recognized as the keeper of the keys to North American spending data
going back to the mid 1980s. “They’re in the board rooms right now talking about budgets and
OPEC is saying what they’re going to do through 2018.”
The timing of the announcement from OPEC and its Russian ally was no doubt helpful to
American drillers, West said. The prolonged nature of the extension that had been due to expire in
March will reassure oil traders and provide investors and executives alike with a degree of comfort
about price stability, he said.

Even as next year’s drilling budgets are in flux in the c-suite, explorers already are poised to
ensnare any price blips stemming from the OPEC-Russia deal. When crude prices rise, shale
producers typically use financial instruments such as swaps and options to lock in prices for
barrels they won’t pump until months from now, a process called hedging.
Hedging Output
“OPEC’s decision helps to underpin the forward curve and gives shale producers the opportunity
to tie up more volume in hedges,” Scott Hanold, an Austin, Texas-based analyst for RBC Capital
Markets LLC, said in a phone interview.
Right now, producers probably can secure hedges based on the U.S. benchmark, West Texas
Intermediate, that provide a floor in the low to mid $50s a barrel, Hanold said. “I would guess that
a lot of hedges have been going in” since the deal extension was announced, he said.
About 60 percent of the expected production by companies in RBC’s coverage universe is already
hedged, “a much fuller hedging book than in previous years,” said Hanold. Still, there’s room to do
more, he said.
To assuage investors demanding that shale explorers live within their means and forego drilling
wells with borrowed money, West said he expects companies initially to announce budgets based
on more conservative estimates of around $50.
Dynamic Budgeting
“But it wouldn’t surprise me to see the overall budgets for North American companies especially,
given how dynamic they can be, to move up throughout the year,” he said.

Andre Burba, partner at the New York-based investment firm Pine Brook Road Partners LLC, said
he doesn’t expect a material revision in drilling budgets based upon the OPEC-Russia decision.
Rather, it’s affirming their original plans before the OPEC meeting.
“The decision is adding much needed stability to this nascent recovery that we’ve seen over the
course of the last year,” Burba, whose firm’s $4 billion under management includes a portfolio of
about a dozen North American explorers, said Friday in a phone interview. “Adding that element of
stability and given the time frame of this extension, it was a very very helpful step.”
Too Rich
Ultimately, shale’s voracious appetite for growth may very well eat the rally that allowed it to grow
in the first place. If output from U.S. shale fields continues expanding next year on the back of
OPEC’s asceticism, individual discipline will slip, member nations will abandon the alliance, and a
new price-killing glut will emerge, according to analysts at ESAI Energy LLC.
“What tastes good today will become too rich later in 2018,” the ESAI analysts said in a note to
clients. As shale output escalates, “the deal will begin to quietly unravel. This means higher prices
in the short-term, but lower prices by 2019.”
Natural gas production in Bakken region increases at a faster rate than oil production
In North Dakota’s Bakken region, the ratio of natural gas production relative to crude oil, known as
the gas-oil ratio, has been gradually increasing since 2008 and has increased at a faster rate
since 2014. More than 90% of North Dakota’s crude oil and natural gas production comes from
the Bakken region, which includes the Bakken and Three Forks formations.
Total North Dakota crude oil production peaked at more than 1.2 million barrels per day (b/d) in
December 2014, but production has since dropped to 1.07 million b/d (as of August 2017), based
on data in EIA’s Monthly Crude Oil and Natural Gas Production Report. The record crude oil

production in late 2014 was the result of increasing crude oilproduction from the Bakken and
Three Forks formations. Despite production declines in 2016, North Dakota remained the second-
largest oil-producing state, accounting for 11% of total U.S. crude oil production.
Source: U.S. Energy Information Administration, Drilling Productivity Report
While oil production has slowed in North Dakota, natural gas production has continued to grow,
reaching a record high of 1.94 billion cubic feet per day (Bcf/d) in August 2017, or the energy
equivalent of about 334,000 b/d of crude oil. Despite the increasing gas-oil ratio, North Dakota still
produces more than three times as much energy from crude oil as from natural gas.
Source: U.S. Energy Information Administration, based on North Dakota Industrial Commission

In tight oil formations like the Bakken and Three Forks—which have low permeability—the gas-oil
ratio tends to increase only gradually over an extended period of time before reaching a certain
point at which it then increases significantly.
As producers extract hydrocarbons from a rock formation, the pressure in the formation eventually
falls below the point at which natural gas naturally separates from the gas-saturated crude oil—a
threshold known as the bubble point. More oil relative to natural gas tends to be produced during
the initial phases of production, after which natural gas production can increase once pressure in
the formation reaches the bubble point.
Source: U.S. Energy Information Administration, based on North Dakota Industrial Commission
In previous years, insufficient infrastructure to collect, gather, and transport North Dakota’s
increasing natural gas production meant more than 35% of the state's gross withdrawals of natural
gas was flared rather than marketed.
In an effort to reduce the amount of flared gas, North Dakota's Industrial Commission established
new targets in 2014 to limit flaring to 10% by October 1, 2020. Based on data from North Dakota's
Industrial Commission, the volume of flared natural gas has declined from more than 0.35 Bcf/d in
2014 to about 0.20 Bcf/d in 2017—about a 40% decline.

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
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Khaled Malallah Al Awadi,
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MS & BS Mechanical Engineering (HON), USA
Emarat member since 1990
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Mobile: +97150-4822502
khdmohd@hawkenergy.net
khdmohd@hotmail.com
Khaled Al Awadi is a UAE National with a total of 25 years of experience in
the Oil & Gas sector. Currently working as Technical Affairs Specialist for
Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy
consultation for the GCC area via Hawk Energy Service as a UAE
operations base , Most of the experience were spent as the Gas Operations
Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility &
gas compressor stations . Through the years, he has developed great
experiences in the designing & constructing of gas pipelines, gas metering &
regulating stations and in the engineering of supply routes. Many years were spent drafting, &
compiling gas transportation, operation & maintenance agreements along with many MOUs for the
local authorities. He has become a reference for many of the Oil & Gas Conferences held in the
UAE and Energy program broadcasted internationally, via GCC leading satellite Channels.
NewBase : For discussion or further details on the news above you may contact us on +971504822502 , Dubai , UAE

New base 04 december 2017 energy news issue 1108 by khaled al awadi

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