Graduation project

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Natural gas discoveries in the eastern
Mediterranean sea
Presented by
Ahmed Sayed Fawzi
Supervisor
Dr Mohamed abdelfattah

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CONTENT
1- Introduction
2- History of gas fields in eastern Mediterranean sea
3- Geology of eastern Mediterranean sea
4- Reserves and recent discoveries
5- Levant Basin
5.1 Composite Petroleum System and Assessment Units
5.2 Offshore exploration and discoveries in Levant basin
5.3 Tamar
5.3.1 Production
5.3.2 Pipeline connection controversy
6 Leviathan gas field
6.1 Introduction
6.2 Rights dispute
7 Aphrodite gas field
8- Assessment of Undiscovered Oil and Gas Resources of the Nile Delta Basin
Province, Eastern Mediterranean
8.2 Assessment Results
9- Oil & gas discoveries in Nile delta provenance
10- Zohar "Supergiant" gas discovery in the Mediterranean sea in Egypt
10.1 The great discovery
10.2 Agreements
10.3 Egypt’s Energy Conundrum
10.4 Important of Zohar to Eni and Egypt
10.5 Israel, Cyprus and the new discovery
10.6 Compare between Zohar and other gas fields in the world
11- Regional oil and natural gas production and consumption..
12- Pipelines
13- Proposed energy infrastructure
14- Export infrastructure
15- Import infrastructure.
16- Regional issues
17- Territorial disputes

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1- Introduction
Recently significant amounts of natural gas have been discovered offshore in the
Eastern Mediterranean. Countries that have so far been dependent on energy
imports will have the opportunity to develop massive gas fields, increase their
energy security and even export natural gas to other regions. The discoveries are
expected not only to affect the energy market, but may also be considered a game-
changer with geostrategic, legal and social implications.
According to a recent estimate initiated by the Lebanese government, 708 BCM of
natural gas may be available offshore south-west Lebanon. The country has
significant gas and perhaps oil potential and is currently in the process of legislation
to regularize gas exploration. These discoveries are all part of the Levant Basin
offshore Israel, Gaza, Lebanon, Syria and Cyprus. Most of the basin is covered by
the Exclusive Economic Zones (EEZ) of Israel, Lebanon and Cyprus and almost
half of it is in Israel’s EEZ. A recent US Geological Survey estimated that the basin
holds close to 3,450 BCM of natural gas and 1.7 billion barrels of oil. The Nile
Delta Basin, in the south-east Mediterranean, situated in Egypt’s and Cyprus’s
EEZ, is estimated to hold even more natural gas (6,315 BCM) and oil (1.8 billion
barrels). Together with the Aegean Basin offshore Greece, it appears that the
Eastern Mediterranean has huge oil and gas potential, and it is clear why there is
worldwide interest in exploration of the region. However, it should be noted that all
the estimations regarding the potential in the area have a very high level of
uncertainty. On the one hand, after many failed drillings in the past, it could turn
out that the basin has less potential than expected.
2- History
The hydrocarbons sector began developing in the eastern Mediterranean
approximately 80 years ago when oil exploration began in Syria following the
successes in neighboring countries such as Saudi Arabia. Commercial oil
production in Syria did not begin in earnest until the 1960s, while oil exploration
activities in Israel and Jordan ramped up in the 1960s and 1970s, although with far
less success than in Syria. Nevertheless, production at very low levels persists in
both Israel and Jordan.
Both Syria and Israel are also natural gas producers, although those sectors did not
develop commercially until the 1980s in Syria and the mid-2000s in Israel. Jordan
has had very low levels of production of both oil and natural gas since the 1980s,
and the country relies primarily on imports to meet internal demand. In Cyprus,
Lebanon, and the Palestinian Territories oil exploration and development is still in
its infancy, however each hopes to capitalize on successful offshore exploration in
the Levant Basin to develop domestic natural gas resources.

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Efforts to move energy resources through the eastern Mediterranean region, located
between the major supply countries in the Middle East and major demand centers in
Europe, have been ongoing for decades. Even before beginning oil and natural gas
operations of their own in the 1960s and 1970s, eastern Mediterranean countries—
notably Syria—often benefitted from transit fees paid to them by nearby exporters
like Iraq and Saudi . Today, there is considerable focus on exploration and new
projects, but international transit remains a key policy consideration of several
eastern Mediterranean countries. As the region continues to discover and develop
hydrocarbon resources, the pressure to increase its role as an important energy hub
is likely to increase.
Gas and oil explorations have been persistently conducted in the region for many
decades. In Israel, small gas fields were discovered in late 1950s in the southern
Judean Desert. Offshore drilling in the Eastern Mediterranean began as early as
1969, but during the next 30 years the 17 exploration wells drilled turned out to be
dry. Only in 1999-2000 were the first major discoveries made offshore Ashkelon.
The first field discovered was Noa and the biggest of the fields was Mary B. The
former was recently developed and the latter started to supply gas to the Ashdod
power station in 2004. The Mary B field (30 BCM) is in the depletion stage and
may later be used as a natural gas storage field. Off Gaza, the Gaza Marine Reserve
was discovered in 1999 and contains more than 30 BCM; the field has never been
developed, mostly due to failed negotiations and the political situation in the area.
The Mary B discovery was not significant internationally, but supplied domestic
needs and demonstrated that the region has great natural gas potential. The next six
exploration wells did not lead to new discoveries until the Tamar field was
discovered in 2009, the largest discovery in the world that year. A year later, the
Leviathan field was discovered representing the largest natural gas discovery in a
decade. While the Mary B field is 250 meters deep and located west of Ashkelon,
the Leviathan and Tamar fields, both discovered by Noble Energy, are 1500-1700
meters deep and located 80-135 km west of Haifa. The Tamar field contains
approximately 275 BCM, and the Leviathan field is estimated to contain 480 BCM.
To put the number in perspective, in 2011 Israel consumed 5 BCM of natural gas.
Therefore, it is clear that, even with demand increasing, the new gas finds could
supply Israel’s gas needs for several decades at least. The Tamar production
platform is expected to be installed by the end of 2012 and production should begin
in the second quarter of 2013.
Other smaller wells discovered in 2009-2012 include the Dalit field west of Hadera
(estimated at 7-8 BCM), the Tanin field north-west of the Leviathan field
(approximately 34 BCM), the Dolphin field south-east of Leviathan (2.3 BCM) and
the Shimshon field west of Ashkelon (16 BCM). In addition, ultra-deep drilling
being conducted in the Leviathan could discover much more natural gas and
perhaps oil, for which there is substantial potential in the region, but has yet to be
discovered. Israel is leading the exploration in the region but other countries are not
far behind. In 2007 Cyprus held the first round of auctions for exploration licenses.
The Aphrodite gas field was discovered in December 2011 west of Leviathan in
“Block 12”.

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The field is believed to hold 200 BCM of natural gas with potential for oil in deeper
horizon. Cyprus is in the process of a second licensing round for 12 more
exploration blocks. Lebanon and Syria have also announced timetables for offshore
licensing rounds. Syria has delayed the process due to the political situation,
whereas in Lebanon the first licensing round is possible as early as 2013.
3- Geology
The eastern Mediterranean region includes eight significant basins (Cyprus basin,
Eratosthenes High, Latakia basin, Levant basin, Judea basin, Nile Delta basin,
Western Arabian province, and Zagros province), with the majority of the historical
hydrocarbon production occurring in the Nile Delta Basin, the Western Arabian
Province, and the Zagros Province. Most of the Nile Delta Basin lies within Egypt's
territorial waters, although there is a small area under Cypriot control.
To date, there have not been any significant discoveries in the Cypriot territory,
although much of Egypt's offshore oil and gas production comes from the area. The
Western Arabian province basin covers large parts of Jordan and Syria, and extends
into Iraq, Saudi Arabia, and Turkey.
Most of Jordan's fields and many of Syria's are in the Western Arabian Province.
The Zagros Province extends from Turkey in the north, through Iraq and Iran,
terminating in the Gulf of Oman in the south. Several of Syria's largest fields are
part of the Zagros Province, but the vast majority of fields in the Zagros Province
are in other countries including Iraq, Iran, and Saudi Arabia. While the Western
Arabian and Zagros Provinces account for most of the historical hydrocarbon
production in the region, most of the focus today is on the Levant Basin.
While most of the historical production in the eastern Mediterranean countries
came from the Western Arabian Province and the Zagros Province, the Levant
Basin is the center of most of the recent exploration activities in the region.

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4- Levant Basin
The Levant Basin Province encompasses approximately 83,000 square kilometers
(km
2
) of the eastern Mediterranean area (fig. 1). The area is bounded to the east by
the Levant Transform Zone, to the north by the Tartus Fault , to the northwest by
the Eratosthenes Seamount, to the west and southwest by the Nile Delta Cone
Province boundary, and to the south by the limit of compressional structures in the
Sinai . The Levant Basin is a deep and long existing geologic structure located in
the eastern Mediterranean Sea.
The southern part of the basin hosts a world-class hydrocarbon province offshore
the Nile Delta. Recent discoveries of biogenic gas and various oil shows indicate
that the central part of the basin, offshore Israel has significant hydrocarbon
potential. To further investigate this area, which is generally under-explored, a
basin-scale study was initiated by the petroleum commissioner in the Israeli
Ministry of Infrastructure.
The reconstructed basin history shows that the Levant Basin was shaped in several
main tectonic stages. Early Mesozoic rifting resulted in the formation of an

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extensive graben and horst system, extending throughout the Levant onshore and
offshore. Late Jurassic to Middle Cretaceous, post-rift subsidence was followed by
the formation of a deep marine basin in the present-day offshore and a shallow-
marine, carbonate dominated margin and shelf near the Mediterranean coastline and
further inland.
A Late Cretaceous and Tertiary convergence phase resulted in inversion of Early
Mesozoic structures and the formation of extensive, Syrian Arc type constructional
structures throughout the Levant Basin and margin. The Tertiary convergence was
further associated with uplift, widespread erosion, slope incision and basinward
sediment transport. A Late Tertiary desiccation of the Mediterranean Sea was
followed by deposition of a thick evaporitic blanket that was later covered by a
Plio-Pleistocene siliciclastic wedge.
The Phanerozoic basin-fill ranges in thickness from 5-6 km on the margin to more
than 15 km in the central part of the basin A variety of potential, structural and
stratigraphic traps were formed in the Levant Basin during the three main tectonic
stages. Possible hydrocarbon play types are: Triassic and Lower Jurassic fault-
controlled highs and rift-related traps; Middle Jurassic shallow-marine reservoirs;
Lower Cretaceous deepwater siliciclastics; the Tertiary canyon and channel system
and associated deepwater siliciclastics found in either confined or non-confined
settings; Upper Cretaceous and Tertiary Syrian Arc folds; and Mesozoic and
Cenozoic isolated, carbonate buildups on structurally elevated blocks. Shallow gas
discoveries in Pliocene sands and high-grade oil shows found in the Mesozoic
section indicate the presence of source rocks and appropriate conditions for
hydrocarbon generation in both biogenic and thermogenic petroleum systems. The
size, depth and trapping potential of the Levant Basin suggest that large quantities
of hydrocarbons can be found offshore Israel.
For this assessment, the Mesozoic-Cenozoic Composite Petroleum System was
defined to include the possibility of viable petroleum source rocks of Triassic,
Jurassic, Lower Cretaceous, Upper Cretaceous, Miocene, and Plio-Pleistocene ages,
all of which have been suggested as potential source rocks within this province.
This composite petroleum system was defined to encompass all petroleum fluids
and mixtures of these fluids in the Levant Basin Province because we could not
completely discriminate between genetic families of oils or gases with available
geochemical data.
Three assessment units (AU) were defined geologically within the composite
petroleum system. The Levant Margin Reservoirs AU encompasses all reservoirs,
from basement rocks to the Pleistocene, occurring east of the pinch-out of
Messinian-age salt and west of the Levant Transform (fig. 2). Reservoirs include
Jurassic and Cretaceous shelf-margin carbonates, nearshore marine sandstones, and
deep-water slope and fan sandstones. The Levant Sub-Salt Reservoirs AU
encompasses all reservoirs within and below continuous Messinian-age salt west of
the eastward pinch-out of the salt (fig. 2). Reservoirs are mainly Mesozoic and

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Paleogene sandstones ranging from incised valley deposits to deep-water slope and
fan sandstones (Gardosh and others, 2006; 2008). The Plio-Pleistocene Reservoirs
AU includes all reservoirs younger than Messinian-age salt west of the pinch-out of
salt, and reservoirs mainly are incised channels, and deep-water slope and fan
sandstones (Aal and others, 2000; Bertoni and Cartwright, 2006) (fig. 2). The Plio-
Pleistocene Reservoirs AU is thought to be sourced mainly by biogenic gas, but this
assessment includes the possibility of thermogenic gas and oil that migrated
vertically from sub-salt source rocks. The Levant Margin Reservoirs AU contains
four oil and four gas fields, the Plio-Pleistocene Reservoirs AU includes eight gas
fields, and the Levant Sub-Salt Reservoirs AU has two discoveries (Tamar, Datil)
that were used in the assessment but are so new that there is no independent refer-
ence as to the size of these discoveries. For this assessment a minimum
undiscovered field size of 5 million barrels of oil equivalent (MMBOE) was used
for the offshore assessment and a 1 MMBOE minimum was used for the onshore
assessment
Extending across a large section of the offshore areas of the eastern Mediterranean,
the Levant Basin is at the center of recent energy exploration in the region. In a
2010 report, the U.S. Geological Survey (USGS) estimated that the Levant Basin
has mean probable undiscovered oil resources of 1.7 billion barrels and, more
significantly, mean probable undiscovered natural gas resources of 122 trillion
cubic feet (Tcf). In context, the combined proved reserves of oil in the countries
included in this report totaled just over 2.5 billion barrels as of January 2013—99.5
percent of which belong to Syria—and proved natural gas reserves of 18.2 Tcf. The
USGS also estimated the mean probable undiscovered resources of natural gas
liquids (NGL) at 3.1 billion barrels. While the USGS estimates do not reflect the
entirety of potential energy resources in the eastern Mediterranean region, the
resources of the Levant Basin likely represent a large part of the overall resource
base. The USGS estimate of 1.7 billion barrels of oil, if discovered, would increase
the region's proved reserves by slightly less than 70 percent, while the 122 Tcf of
natural gas represents more than six times the region's current proved reserves.

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An additional 1.7 billion barrels of oil in the Levant Basin would meet regional
demand for roughly 20 years at current levels of consumption, while 122 Tcf of
natural gas could meet current regional demand almost indefinitely. Nearly all the
recent significant discoveries in the Levant Basin were of natural gas, and, while
offshore exploration may eventually yield recoverable quantities of oil, to date
there have not been any commercially viable discoveries.
4.2 Offshore exploration and discoveries in Levant basin
Recent natural gas discoveries in the Levant Basin have significantly altered the
energy outlook in the eastern Mediterranean. Success in Israel, Cyprus, and the
Palestinian Territories, spurred additional exploration in the region, and Lebanon
and Syria both hope to launch exploration programs soon.
The discovery of the Noa field in 1999 and the Mari-B field in 2000 and
discoveries in 2009 (Dalit and Tamar), 2010 (Leviathan), and 2011 (Aphrodite and
Tanin) by U.S. firm Noble Energy confirmed the presence of significant quantities
of natural gas in the Levant Basin. The largest offshore discovery in the eastern
Mediterranean before the Zohar field discovered by ENI is the Leviathan field—
located approximately 80 miles off the coast of Israel and situated in water that is
more than 5,000 feet deep—which holds 18 Tcf in estimated recoverable
resources., as some estimates indicate there could be up to 600 million barrels of oil
located in the field.

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Another significant Israeli find, the Tamar field, began operations in April 2013,
and the Dalit and Tanin fields should come online sometime in the next decade.
Recent revisions to resource estimates for the Tamar field brought the estimated
recoverable reserves to 10 Tcf, enough to meet present levels of Israel's demand for
decades. The Tamar field started production in a surprisingly short period of time,
with less than five years between the discovery and commercially-viable
production.
In addition to the discoveries in Israel, Cyprus has also had successful exploration
in its offshore territory. Thus far, the most notable natural gas discovery in Cypriot
waters was the Aphrodite field in Block 12 made by Noble Energy in 2011,
estimated to contain 7 Tcf of natural gas. Noble Energy—the company behind most
of the major natural gas discoveries in the region—began drilling its second well in
Block 12 in June 2013.
Government officials aim to capitalize on the exploration success in Block 12 to
pursue additional resources in Cypriot waters, and hope to discover between 30 and
40 Tcf of additional natural gas.
A bidding round for several of the country's offshore blocks closed in 2012, with
awards going to a diverse group of international companies and consortia. Italian
company Eni and South Korean company Korean Gas Corporation (KOGAS) won
the bid for blocks 2, 3, and 9, while the French firm Total came away with Blocks
10 and 11.
Another potentially significant find in the Levant Basin is the Aphrodite-2 well, on
the Israeli side of the maritime boundary with Cyprus. The Aphrodite-2 natural gas
could be part of the same geologic structure as Cyprus' Aphrodite field and may
have over 3 Tcf of technically recoverable resources. Should the Aphrodite-2 prove
to be a part of the same structure as Cyprus' field, the two countries will need to
negotiate a utilization agreement before production begins.
Similarly, exploration in the area straddling the maritime boundary between Israel
and the Palestinian Territories indicates that there are potentially significant
quantities of hydrocarbons in the area.
The Gaza Marine field holds an estimated 1 Tcf in recoverable resources, and in
September 2012, the Palestinian Authority and Israel discussed developing the
offshore Gaza territory, although no firm agreements are in place. proved and
probable reserves at the Meged field—discovered in 2004 by Givot Olam Oil
Exploration—are in excess of 10 million barrels, and they may extend
intoPalestinian territory.

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Noble Energy has been at the vanguard of natural gas exploration in the
Mediterranean Sea. In his presentation at the Frankfurt Gas Forum, John
Tomich, Cyprus Country Manager, Noble Energy Inc., recalled that Noble had
entered Israel in 1998 and in the early 2000's had made its first discovery offshore
Israel: 1 TCF of natural gas in the Mari-B discovery.
“Basically, it started the Israel natural gas industry,” he said, “and led to significant
market penetration for natural gas for electric power generation in Israel.”
Noble, he said, had drilled a number of wells after that and made additional
discoveries, but the next major milestone was in 2009, when the company
discovered the Tamar gas field, roughly 10 TCF of gas; the next year, Noble drilled
the Leviathan, which was close to 20 TCF. Together with its partners, Avner Oil &
Gas Exploration L.P. (part of Delek Group) and other Israeli companies, he said
Noble had roughly 30 TCF of gas, either producing or forthcoming production.
More activity occurred in 2011, when the company drilled “Cyprus A,” in the
Aphrodite field and Block 12 of the Cyprus discovery. Mr. Tomich explained that
the production facilities at Mari-B formed the basis for the subsequent
development, Tamar, an ultra-deep water development. “It sits at roughly the same
water depths as Leviathan and Aphrodite, roughly 1,700 meters of water depth.
Tamar came on stream in April of this year, 2013.” He said Tamar marked a
number of firsts for both Noble and the industry: “It was a very aggressive
development timetable, roughly 51 months from discovery to first-gas, which is
moving, if you look statistics-wise at worldwide data, ultra-deep development takes
between 5 and 10 years from FID to first production, so we were very pleased for
this project to come together like it did,” he said.
Another first, according to Mr. Tomich, was that there were double flow lines from
sub-sea well completions to the production platform at Mar-B. “These are the
longest flow-lines in the world, 150 kilometers long, climbing from water depths of
1,700 meters to roughly 3-400 meters at Mari-B.” Tamar, he reported, was having
significant impact for all stakeholders. Production there began in late March/early
April 2013, he added, “The development was completed in record time and under
budget. It has had very high reliability to date. Obviously, it's less than a year, but
the reliability has been superb and it's achieved very high output: over 1 BCF/day.”

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According to Mr. Tomich, natural gas had become the fuel of choice for Israel. He
said that the Supreme Court of Israel had recently announced it would allow
exports to occur.
“We're looking at various export options and we'd like to target start-up for late
2018. The Cyprus discovery underpins Noble's long-term profile in the region,” he
said.
He then proceeded to show delegates the “structural closure” of the Cyprus
development, which provided trapping. Two wells, he said, had been drilled and
Noble was working with the Cypriot government on an LNG project, which would
be expandable.
“We could start with Aphrodite and, as further resources are found, offshore
Cyprus and other blocks, they can be folded into trains and that would all be
governed by an umbrella agreement, which is being discussed with the government
of Cyprus,” he explained. However, he added that Noble and the government were
looking at all options (floating LNG and CNG, as well as pipeline projects),
although an LNG facility was the means of choice.
“It provides greater flexibility than any other means in terms of marketing the
project,” said Mr. Tomich, who admitted: “It is an expensive option and it does take
time. It also provides the basis for bringing benefits to the people of Cyprus, such
as more jobs, especially during the construction phase of the plant, and then fewer
but more technically advanced jobs later on.”
Noble, he said, was also looking at ways to accelerate bringing gas to the shores of
Cyprus to provide fuel for the domestic electric power generation market, because
the country currently had some of the highest prices for electricity, but that market
was small and getting smaller in the midst of the economic crisis there.
He explained: “To underpin the very high CAPEX costs that are required for
development in ultra-deep water in this type of gas field, we need to have a major
export project to go with supplying the domestic market – that's the challenge.
We've got to ensure sufficient resource, which is the ongoing effort on the technical
side. We've got to select an adequate method for developing and marketing the
product and then we've got to work within the limits that are set by country and
regional politics. In October, Noble revealed that an appraisal well in the Aphrodite
had flowed with gas at very significant rates. “We estimate that these kinds of
reservoirs could be capable of flowing up to 250 MCF/day, which is roughly
equivalent to what we've experienced in Tamar and Leviathan, excellent quality
reservoirs, world-class,” said Mr. Tomich, who said the updated resource estimate
was 3.6-6 TCF (with a mean of 5).

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4.3Tamar
The Tamar gas field is a natural gas field in the Mediterranean Sea off the coast
of Israel. The field is located in Israel's exclusive economic zone, roughly 80
kilometres (50 mi) west of Haifa in waters 1,700 metres (5,600 ft) deep. The Tamar
field is considered to have proven reserves of 200 billion cubic metres (7.1 trillion
cubic feet) of natural gas, while the adjoining Tamar South field has 23 billion
cubic metres (810 billion cubic feet). Together, they may have an additional 84
BCM of "probable" reserves and up to 49 BCM of "possible" reserves (reserves
having a 10% probability of extraction). At the time of discovery, Tamar was the
largest find of gas or oil in the Levant basin of the Eastern Mediterranean Sea and
the largest discovery by Noble Energy. Since Tamar's discovery, large gas
discoveries have been made in other analogous geological formations of the same
age in the region. Because Tamar was the first such discovery, these gas containing
formations have become collectively known as Tamar sands.
4.3.1 Production
Production is carried out by five wells connected by a 93 mile long subsea double
pipe tie-back to a gas processing platform located offshore Ashkelon. First
commercial gas delivery took place on 1-April-2013 after four years of
development work. The total initial delivery capacity is 985 MMCF per day or 10
BCM annually. Current contracts completely utilize this entire capacity. Therefore,
an upgrade of the supply infrastructure from the processing rig to the onshore

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reception station in Ashdod is planned by 2016. In the first phase, capacity will be
increased to approximately 1,200 MMCF/day and later to approximately 1,500
MMCF/day, with the latter upgrade possibly including the usage of the now-
depleted Mari-B field, located nearby Tamar's processing platform, as a gas storage
reservoir
4.4 - Leviathan gas field
The Leviathan gas field is a large natural gas field located in the Mediterranean
Sea off the coast of Israel, 47 kilometers (29 mi) south-west of the Tamar gas
field. The gas field is located roughly 130 kilometers (81 mi) west of Haifa in
waters 1,500 metres (4,900 ft) deep in the Levantine basin, a rich hydrocarbon area
in one of the world's larger offshore gas finds of the past decade. According to
some commentators, the gas find has the potential to change Israel's foreign
relations with neighboring countries Turkey and Egypt. Together with the nearby
Tamar gas field, the Leviathan field is seen as an opportunity for Israel to become a
major energy player in the Middle East.
In July, 2010, Noble Energy announced that seismic studies indicated there was a
50% chance of the Leviathan field containing natural gas, with the potential reserve
size being estimated at 16 trillion cubic feet (450 billion cubic metres). The initial
exploration well, Leviathan 1, was drilled to a depth of 5,170 metres (16,960 ft) and
the discovery was announced on December 30, 2010. The cost of drilling the
exploration well was $92.5 million. The well was drilled by Noble's Homer
Ferrington rig. The second stage of drilling of the Leviathan 1 well was intended to
reach a depth of 7,200 metres (23,600 ft), which would include an additional

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natural gas reserve and potentially 600 million barrels of oil. While the gas
discovery at -5170m was made in theTamar sands layer which was already known
to contain gas, the additional oil and gas potential exists in layers that have not been
explored in the Levant basin. Noble has twice failed to reach the deeper layers due
to technical challenges with drilling to the extreme depths involved. However,
during drilling towards the intended target some gas was detected and as of 2012
Noble still had plans to explore those layers.
The Leviathan gas field was the largest gas field in the Mediterranean Sea until the
August 2015 discovery of the Zohr prospect gas field off the coast of Egypt, only 6
km from Cyprus's Block 11. Leviathan is the largest discovery in the history
of Noble Energy. Noble Energy operates Leviathan with a 39.66% working
interest; Delek Drilling holds 22.67%; Avner Oil Exploration holds 22.67%; and
Ratio Oil Exploration holds the remaining 15%.
4.4.1 Rights dispute
The existence of the Leviathan gas fields poses several challenges to states in that
area of the Eastern Mediterranean, in terms of cooperation between them, as well as
for the wider Mediterranean energy context. After discovery of the Leviathan gas
fields in 2010, Lebanon argued that the field extends into Lebanese waters.
Lebanon’s Parliament Speaker Nabih Berri stated that Israel is "ignoring the fact
that according to the maps the deposit extends into Lebanese waters," Agence
France-Presse reported on June 9. Israeli Minister of National Infrastructures Uzi
Landau responded "We will not hesitate to use our force and strength to protect not
only the rule of law but the international maritime law," in an interview. In August
2010, Lebanon submitted to the United Nations its official view regarding the
maritime border, indicating that it considered the Tamar and Leviathan gas fields to
be outside Lebanese territory (though it indicated other prospective fields in the
region may be within Lebanese territory). The US expressed support for the
Lebanon proposal
4.5 Aphrodite gas field
Aphrodite gas field is an offshore gas field off the southern coast
of Cyprus located at the exploratory drilling block 12 in the country's
maritime Exclusive Economic Zone. Located 34 kilometres (21 mi) west
of Israel's Leviathan gas field, block 12 is believed to hold 3.6 to 6 trillion cubic
feet (100×109
to 170×109
m3
) of natural gas.
Noble Energy received the concession to explore block 12 in October 2008 In
August 2011, Noble entered into a production-sharing agreement with the Cypriot
government regarding the block's commercial development. Sources in Cyprus
indicated in mid-September that Noble had commenced exploratory drilling of the
block. For the Cyprus population the Aphrodite gas field can boost the local
economy to counter rising unemployment.

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According to Noble Energy, a total gross unrisked deep oil potential is 3.7 billion
barrels (590×106
m3
). The field has a gross mean average of 7 trillion cubic feet
(200 billion cubic metres) of natural gas with an estimated gross resource range of
5–8 trillion cubic feet (140×109
–230×109
m3
).
5- Assessment of Undiscovered Oil and Gas Resources of the
Nile Delta Basin Province, Eastern Mediterranean
The U.S. Geological Survey (USGS) estimated the undiscovered oil and gas
resources of the Nile Delta Basin Province as part of a program aimed at
estimating the recoverable oil and gas resources of priority basins around the
world. The province encompasses approximately 250,000 square kilometers of
the eastern Mediterranean area (fig. 1). It is bounded to the west by the
approximate edge of the Nile Cone, to the north by the Strabo, Pytheus, and
Cyprus Trenches, to the east by the Levant Basin Province boundary, and to the
south by the approximate edge of compressional structures in northern Egypt),
which also corresponds to the general updip limit of Neogene deltaic strata in
Egypt. This assessment was based on published geologic information and on
commercial data from oil and gas wells, fields, and field production. The USGS
approach is to define petroleum systems and geologic assessment units and
assess the potential for undiscovered oil and gas resources.

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The Mesozoic-Cenozoic Composite Petroleum System was defined to include
the possibility of viable source rocks of Jurassic, Cretaceous, Oligocene,
Miocene, Pliocene, and Pleistocene ages (Abdel Aal and others, 2000, 2001;
Dolson and others, 2001a, b; Vandre and others, 2007). Four assessment units
(AU) were defined geologically within the composite petroleum system. Two of
the assessment units—Eratosthenes Seamount AU and Mediterranean Ridge
AU—were defined northward of the Nile Cone but were not quantitatively
assessed. The two assessed areas are the Nile Cone AU and Nile Margin
Reservoirs AU .
Oil and gas were generated from multiple Mesozoic and Cenozoic sources
including: (1) hypothesized Jurassic marine and terrigenous shale; (2)
Cretaceous argillaceous shales and limestones; (3) Oligocene and Miocene
terrigenous source rocks; and (4) possibly biogenic sources (Vandre and others,
2007). Source rocks are thermally mature in deeper parts of the province .
Petroleum charge is confirmed by more than 100 producing fields, numerous oil
seeps, mud volcanoes, and gas chimneys imaged on seismic profiles (Loncke
and others, 2004). Reservoirs are Mesozoic to Paleogene carbonate and clastic
reservoirs and Neogene-Quaternary deltaic, nearshore marine, deep-water slope
channel, and sheet and fan sandstones (Cross and others, 2009; Samuel and
others, 2003) and Messinian-age (latest Miocene) incised-valley-fill deposits
(Dolson and others, 2001a). Traps are structural and stratigraphic with numerous
modifications because of inversion, salt removal, normal faults, growth faults,
and mass transport (Loncke and others, 2006). Migration was enhanced by major
intersecting fault systems. Lithologic and diagenetic seals were effective in
creating pressure compartments (Nashaat, 1998).
The Nile Margin Reservoirs AU is assumed to be sourced from deeper thermally
mature source rocks, but currently only one oil field of minimum size is present
in the AU. The Nile Cone AU is thought to be sourced mainly from thermally
mature Neogene deltaic source rocks, but also there might be a significant
biogenic gas component (Vandre and others, 2007). The Nile Cone AU contains
two oil fields and 126 gas fields.
The geologic model used in the assessment of the Nile Delta Basin was derived
from comparison of geologic analogs, oil and gas production data, proved
reserves, and potential oil and gas resources for the maturely explored Niger
Delta Province (Brownfield and others, 2010). The USGS used a minimum
undiscovered field size of 5 million barrels of oil equivalent (MMBOE).

18
5.2 Assessment Results
The mean of the distribution for undiscovered oil is about 1,763 million barrels of
oil (MMBO), with a range from 491 MMBO to 4,266 MMBO. For undiscovered
gas, the total mean volume is 223,242 billion cubic feet of gas (BCFG), with a
range from 92,614 to 425,935 BCFG. For natural gas liquids, the total mean
volume is 5,974 million barrels of natural gas liquids (MMBNGL), with a range of
2,451 to 11,464 MMBNGL. By far the largest resource Is estimated to be in the
Nile Cone AU, with a mean volume of 217,313 BCFG and 5,789 MMBNGL.
These estimates represent technically recoverable oil and gas resources; no attempt
was made to estimate economically recoverable resources.
6- OIL & GAS DISCOVERIES IN NILE DELTA PROVENANCE

19
7- THE SUBER GAIN GAS DESCOVERY IN THE MEDITERANEAN SEA
Eni has made a world class supergiant gas discovery at its Zohr
Prospect, in the deep waters of Egypt . the discovery well Zohr 1X NFW
is located in the economic waters of Egypt’s Offshore Mediterranean, in
4,757 feet of water depth (1,450 metres), in the Shorouk Block, signed in
January 2014 with the Egyptian Ministry of Petroleum and the Egyptian
Natural Gas Holding Company (EGAS) following a competitive
international Bid Round. Eni called the field a “supergiant” gas field and
claimed that it “could become one of the world’s largest natural-gas
finds.”
According to the well and seismic information available, the discovery
could hold a potential of 30 trillion cubic feet of lean gas in place (5.5
billion barrels of oil equivalent in place) covering an area of about 100
square kilometers. , potentially making it the twentieth largest in the world
and the largest in the Mediterranean sea located in the Mediterranean
Sea at the company’s Zohr prospect about 120 miles off the Egyptian
coast in the Shorouk block , The announcement of the discovery came a
day after a Cairo meeting between the Egyptian President Abdel-Fattah
el-Sisi and Eni CEO Claudio Descalzi, according to the president’s office
Eni expects to make a final investment decision about developing the
field later this year, setting up development drilling in 2016 and 2017 with
initial production on stream by 2018.

21
Until the Zohr discovery, Egypt had an estimated 64.8 trillion tcf of natural
gas reserves sitting primarily in the Mediterranean Sea, the Nile Delta, and
its western desert, making it a medium-sized player in the natural gas
market . This exploration success will give a major contribution in satisfying
Egypt’s natural gas demand for decades . Eni will immediately appraise the
field with the aim of accelerating a fast track development of the discovery
that will utilise at best the existing offshore and onshore infrastructures.
Zohr 1X NFW was drilled to a total depth of approximately 13,553 feet
(4,131 metres) and hit 2,067 feet (630 metres) of hydrocarbon column in a
carbonate sequence of Miocene age with excellent reservoir characteristics
(400 metresplus of net pay). Zohr’s structure has also a deeper Cretaceous
upside that will be targeted in the future with dedicated well.
First, total investment costs, which are likely to run up to $7 billion, will be
borne by Eni but ultimately paid by Egypt. Second, production will require
Eni to drill 4,300 meters at a depth of 1,450 meters below sea level, a very
expensive endeavor
Even more oil could be found at the field during the course of further
exploration, potentially amounting up to 40 trillion cubic feet (1.1 trillion
cubic meters), Claudio Descalzi told Financial Times
7.1 Agreements
Before Egypt sees any gas, Eni will take up to 40 percent of the field’s
output to recover its development and exploration costs, with a yearly
recovery limit of 20 percent of Eni’s total investment costs. The remainder of
the production will be split between Egypt and Eni somewhere in the range
of 60-40 to 69-31 (EGAS-Eni) depending on the production volume,
whereby higher levels of production correlate to higher percentages for
EGAS.
7.2 Egypt’s Energy Conundrum
Egypt’s transformation from exporter to importer was not only predictable; it
was largely avoidable. Until recently, the government’s firm ceiling price for
purchasing natural gas from foreign operators, standing at $2.65/million
British thermal units (MMBtu), was well below global standards . With many
of Egypt’s reserves being deep-water finds in the Mediterranean basin, the
government’s price ceiling made monetization commercially unviable, as
steep deep-water production costs coupled with low government purchase

21
prices left unattractive profit margins for foreign energy companies.
Coupling this with Egypt’s state of instability since 2011, many foreign firms
viewed investment in Egypt as a non-starter.
Indeed, even though production in existing wells started to decline in 2010,
no new exploration contracts were signed between 2011 and 2013. By
2015, production had fallen to 4.8 billion cubic feet per day (bcf/d), a
contraction of 13.1 percent from 2014 and 22.3 percent since 2009.
Simultaneously, Egypt’s natural gas consumption has increased. Even
though demand growth, encouraged by low subsidized energy prices and a
growing population, averaged 6 percent per year between 2005 and 2010,
supply growth helped offset any energy deficit issues—until production
started to decline.
Hence, while government reprising initiative and subsidy reforms early on
might have slowed the growing imbalance of supply and demand, Egypt’s
post-revolutionary governments did not adequately act before gas deficits
crippled Egypt’s economy. In the fiscal year 2014-2015, Egypt’s natural gas
deficit amounted to nearly 1 bcf/d, and this is expected to grow to 2.5 bcf/d
by fiscal year 2017-2018. The growing deficit, coupled with Egypt’s
dependence on natural gas for electricity generation, not only turned net
exports into net imports, but also led to power shortages across Egypt, most
notably in heavy industries such as steel and cement. Until Eni’s Zohr
discovery, these developments painted a stark picture for Egypt’s future.
For most of the past decade, international energy producers have been able
to earn only $2.50 to $2.65 per mmbtu for the natural gas that they sold to EGAS,
the Egyptian domestic natural gas company. This pales in comparison to most
global natural gas prices, which at times have exceeded $15 per mmbtu. (Under the
terms of the deals by which international oil companies operate in Egypt, Cairo can
force them to sell at below-market rates.)
Making matters worse, Cairo has struggled to pay international oil companies. By
late 2013, Egypt owed energy firms an estimated $6 billion to $7 billion, prompting
the firms to hold off on numerous exploration projects. Reduced investment
resulted in lower Egyptian production as older fields and wells saw production
declines. Between 2012 and 2014 alone, Egyptian production fell from 61 billion
cubic meters to 49 bcm.

22
7.3 Important of zahr to eni and Egypt
Despite a potentially difficult payment schedule, Eni, which faced
substantial losses in Libya and recently had to cut its dividend payments,
will find that its discovery is a boon to its company and shareholders. Even
if Eni does not see revenue from the find for at least four years, and
becomes a larger creditor to Egypt in the process, the find will reflect well in
the minds of investors and most likely support its share price
Moreover, the new Zohr field could turn Egypt’s economic fortunes around.
While global market factors and domestic needs negate Egypt’s ability to
translate the Zohr discovery into gas export . Egypt’s domestic industrial
base could find that it can confidently resume manufacturing capacity
expansions, and foreign investors may grow to look more favorably at
industrial investment in Egypt. Indeed, the Zohr field could translate
positively for all parties involved.
Egypt’s massive gas field is considered much more profitable for the Italian
company than the Mamba-Prosperidade gas complex in Mozambique and the
Kashagan oil field in Kazakhstan, where ENI also holds relevant stakes . While
Eni’s new discovery is unlikely to translate into exports for some time, it
does have the potential to alleviate the gap between supply and demand.
Nonetheless, it does not do so without risks for both Eni and Egypt. the
Zohr field discovery could be the best economic news Egypt has received in
years, allowing for resumed industrial growth and potential energy self-
sufficiency—that is, unless Eni intends to take its share of production
elsewhere potential, it provides the necessary resources for Egypt to
become once again energy self-sufficient, in turn positively affecting Egypt’s
economic climate.
Egypt’s domestic industrial base could find that it can confidently resume
manufacturing capacity expansions, and foreign investors may grow to look
more favorably at industrial investment in Egypt.
Indeed, the Zohr field could translate positively for all parties involved
Excess production from the Zohr Prospect could, indeed, be treated at ENI’s
liquefied natural gas (LNG) facility in Damietta, near Egypt’s Mediterranean city
of Port Said, and then shipped to Italy
In this prospect, the Zohr gas deposit will strengthen Italy in its quest to find new
energy suppliers, so as to limit its main dependence on Russia, Libya and Algeria.

23
The natural gas find at the Zohr Prospect will satisfy Egypt’s own domestic natural
gas demand for at least a decade . With 40 percent of total production allotted to
cost recovery and at least 31 percent of the remaining production under
Eni’s ownership, the Zohr field provides ample income for Eni to both
recover its capital costs and bring in revenue—a revenue stream that, in
dollar terms, would provide Eni with around $1.13 billion per year.
Egypt chooses to purchase Eni’s share, Eni could potentially be
compensated in either cash or gas. If Eni is paid in cash, Egypt would owe
the company up to $2.5 billion a year—$1.4 billion for recovery costs for five
years and a further $1.1 billion for Eni’s share of production. Alternatively,
Egypt could agree to pay in gas, in which case Eni would likely try to export
it as LNG. Each possibility comes with its own respective caveat
Israel, Cyprus and the new discovery7.4
Egypt's falling production levels had led Cyprus and Israel to believe they
could step in to supply Egypt's needs. Since Israel's domestic energy needs
would account for just 60 percent of Leviathan's potential production, the
rest would have to be exported for the project to make economic sense.
Eni's announcement has therefore put the entire Leviathan project in
jeopardy. Israel had hoped to see Egypt become energy dependent on
Israeli natural gas to strengthen their strategic relationship. But even though
Israel will not be able to use energy to build its relationship with Cairo,
energy security in Egypt also improves the chances of government stability.
And this would benefit Israel, which wants to see the military remain the
core pillar of the Egyptian state.
In 2011, Noble Energy discovered the Aphrodite natural gas field in Cypriot waters
a year after finding the Leviathan natural gas field in Israeli waters. Both fields,
however, are expensive deepwater fields far from traditional natural gas markets
such as Europe. Any export project to supply those markets — such as floating
liquefied natural gas options or a pipeline to Turkey — could become prohibitively
expensive now that Egypt has had another major natural gas field discovery.
Both Eni's and Noble's natural gas could be brought onstream by 2020. Proximity,
the simpler approval process in Egypt and its overall higher potential resource base
mean that Eni's project has likely vaulted ahead of Leviathan.

24
Since Israel's domestic energy needs would account for just 60 percent of
Leviathan's potential production, the rest would have to be exported for the project
to make economic sense. Eni's announcement has therefore put the entire Leviathan
project in jeopardy.
Israel had hoped to see Egypt become energy dependent on Israeli natural gas to
strengthen their strategic relationship. But even though Israel will not be able to use
energy to build its relationship with Cairo, energy security in Egypt also improves
the chances of government stability. And this would benefit Israel, which wants to
see the military remain the core pillar of the Egyptian state.
Before the revolution, Egypt shipped natural gas to Jordan and Israel by pipeline
and processed LNG at plants in Idku and Damietta for sale overseas. According to
the Energy Information Administration (EIA), Egypt is the second largest natural
gas producer in Africa after Algeria.
In response to the declining natural gas output and growing gas demand, Egypt had
been considering building a pipeline to a field off Cyprus as well as securing
supplies from the giant Leviathan field offshore Israel. Both of these potential deals
are suddenly being reviewed in light of the Zohr discovery, which will change
energy development in this region of the Mediterranean Sea. The Egyptian
government suggests the discovery will not upend those private company deals.
The Leviathan field is estimated to contain 22 Tcf of natural gas, putting it in the
giant category, but the plan to use idled Egyptian LNG facilities owned by BG
Group (BG-NYSE) to export LNG will need to be reassessed. The investors in the
Leviathan field recently agreed to supply gas to Jordan, but that was expected to
use the existing pipeline from Egypt. That deal may be subject to review given the
potential for Egypt to be able to continue to supply Jordan from this new field.
The Zohr discovery announcement came at the same time the Israeli Knesset was
scheduled to debate the cabinet’s decision to allow the Leviathan development to
move forward.
Members of the opposition party in the Knesset believe that the Leviathan deal is
too lucrative for the investors and results in gas prices that are too high for Israeli
consumers . A rejection of the Leviathan deal could force the owners of the field to
reconsider its development, which has been delayed since its discovery in 2010,
and pressure the Israeli government to strive for an agreement with more favorable
prices for consumers.

26
8 - Regional oil and natural gas production and
consumption
Most of the current production of oil and natural gas in the eastern Mediterranean is
in Israel and Syria, which together account for 99 percent of all oil and natural gas
production in the region.
Began in 2011 have dramatically altered the energy outlook for the region, as
Syrian oil and natural gas production continues to drop, and natural gas flows from
Egypt—a key source of natural gas to the region—declined dramatically. Israel is
the only other eastern Mediterranean country with significant hydrocarbon
production (natural gas), although developments in the Levant Basin and elsewhere
could alter the outlook for several countries in the region.
To meet expected rising demand, countries in the region will need to either produce
or import additional energy supplies. Israel's successful development of offshore
natural gas fields significantly altered its energy profile, as the country now projects
to meet internal natural gas demand for years. Those volumes will also help it
reduce petroleum consumption.
Other countries in the region hope to follow suit, but progress has been uneven. If
they are unable to produce oil or natural gas domestically, those countries will need
to import energy supplies from outside the region. With unrest in nearby suppliers
like Iraq and Egypt, procuring such supplies may prove difficult.
Syria is the region's only significant oil producer, but it is not a major supplier to
other countries in the region at this time. Significant gaps between regional oil
production and oil consumption totals indicate that the region requires high levels
of petroleum imports to satisfy demand. In addition, the reserves to production ratio

27
indicates that there is only enough economically recoverable oil presently available
to maintain current production rates for 20 years. If regional consumption patterns
shift away from imports towards the use of more local resources, the region will be
self-sufficient for less than 10 years given current levels of proved reserves. Of
course, imports, exports, the availability and viability of unconventional resources,
changing demand patterns, and new discoveries will all combine to change supply
dynamics in the region. The eastern Mediterranean region's natural gas market
continues to mature, and even without additional exploration and development the
region's reserves are enough to meet current demand levels for over 40 years.
In 2011, the combined dry natural gas production in the eastern Mediterranean was
378 Bcf, while total consumption was 441 Bcf. Israel and Syria accounted for
nearly all of the region's gross production and 92 percent of its consumption.
Recent declines in Syrian natural gas production due to instability in the country
will be partly offset by growth elsewhere in the region, especially in Cyprus and
Israel where a number of recent discoveries should come on-line in the coming
years. Regional natural gas consumption dropped by 23 percent between 2010 and
2011, from 571 Bcf to 441 Bcf. This 23-percent decline came largely as a result of
interruptions in flows from Egypt (which previously exported natural gas to Israel,
Jordan, Lebanon, and Syria) and the onset of violence in Syria
Eastern Mediterranean oil production and consumption 2003-2012
Source u.s.Energy information Administration

28
9 - Pipelines
The Arab Gas Pipeline (AGP) runs from el-Arish in Egypt through Jordan and into
Syria. From Syria, the AGP has a spur to Lebanon, and plans call for the pipeline to
eventually connect with Turkey, but ongoing hostilities in Syria make that prospect
unlikely in the near term. Following interruptions during 2010 and 2011 due in
large part to attacks on the pipeline in the Sinai Peninsula, flows to Jordan have
stabilized, but at levels far below the contract requirements. Recent unrest in Egypt
could further reduce flows. Egypt also has an export pipeline to Israel (from al-
Arish to Ashkelon), but volumes were intermittent over the past several years and
are not currently available.

29
Active, inactive, and proposed pipelines in the eastern Mediterranean

31
Arab gas pip line
10 - Proposed energy infrastructure
The effects of unrest in Egypt and Syria limit the use of existing international
energy
infrastructure in the region, but the recent offshore natural gas finds give new hope
to several
new international projects.
11 - Export infrastructure
Plans to develop the region's export infrastructure are focused primarily on natural
gas volumes from the Levant Basin, but there are also a few international oil
projects that could become viable in the next few years.
Cyprus hopes to begin exporting natural gas from the Aphrodite field by 2019. The
key to this plan is the construction of a new LNG terminal at Vasilikos. That
facility could be operational as early as 2019, with construction slated to begin in

31
2015. Plans call for three liquefaction trains at the terminal, each capable of
producing 5 million tonnes of LNG per year.
Pre-front-end engineering design work on the proposed facility and an associated
pipeline should conclude in 2013. Cyprus aims to incorporate offshore Israeli
natural gas production as well as domestic volumes to supply the LNG facility as
part of the country's broader strategy of becoming an energy hub in the region. As
of May 2013, no agreements between Cyprus and Israel were in place.
There has also been talk of tying the Israeli offshore volumes into the Cyprus
infrastructure being built for their LNG facility at Vasilikos, but at this time Israel
appears to prefer a domestic option. The discoveries of the Tamar and Leviathan
fields (among several others) should allow the country to become a significant
exporter of natural gas in the next decade. There are competing proposals to build
pipelines and LNG infrastructure to support natural gas exports, but deliberations
about how Israel will get its natural gas to market are still ongoing.
A recently-released report by the Natural Gas Inter-Ministerial Committee
suggested that any development plans should guarantee Israeli supply for 25 years,
exports should not exceed 500 billion cubic meters (17.7 Tcf), and any LNG export
facility would be best placed within Israel. One option is for Israel to export natural
gas volumes as LNG from a floating liquefied natural gas (FLNG) installation off
the Mediterranean coast. One plan, the Tamar FLNG project, is in its second phase,
and could begin operations by 2017.
The FLNG facility would draw on volumes from the nearby Tamar and Dalit fields
and be able to export up to 3 million tonnes per year (144 Bcf per year). Estimates
on the ultimate cost of this proposal are somewhere around $5 billion. Another
(more expensive) option is to build an LNG facility onshore in Israel, but this
option remains cost-prohibitive both in terms of construction costs and security
costs during operation of the facility.
There are already plans underway to have Israeli firms supply natural gas to
Jordanian industrial facilities on the coast of the Red Sea. Israel also has plans to
upgrade the Eilat port on the Red Sea to 160,000 cubic meters of natural gas
storage with a connection to the Ramat Yotam facility (1.2 million cubic meters of
storage capacity).
Given Jordan's growing demand for natural gas, an agreement on exports may
occur, but political factors complicate the issue and could hinder cooperation
between the two countries. Egypt is another possible destination, as the country
already has the infrastructure necessary to receive and process natural gas into
LNG. Rising demand in the country means that additional volumes are necessary in
the near term. Cooperation between Israel and Egypt in the natural gas sector is

32
unlikely to occur in the short term given the deterioration of relations since the
onset of unrest in 2011 in Egypt.
Additionally, the el- Arish-Ashkelon pipeline already connects the two countries,
and since Egypt suspended deliveries to Israel (and other countries in the region via
the Arab Gas Pipeline) beginning in 2011, the pipeline remains a possibility for
conversion. As with Jordan, politics will likely determine the nature of the Israel-
Egypt energy relationship in the near term. The recent improvement in relations
between Turkey and Israel makes a direct natural gas pipeline between the two
countries a possibility. The pipeline would probably be offshore so volumes from
Cyprus (and perhaps Lebanon in time) could also feed into the pipeline. No formal
arrangements were in place as of May 2013. Following the Aphrodite discovery,
and those in nearby Israeli waters, Cyprus intends to become an important energy
hub in the eastern Mediterranean region.
Cyprus could capitalize on its location between major supply and demand centers
and the Suez Canal, which is an important oil transit chokepoint. To that end, a
project by Vitol Tanks Terminals International (VTTI) to build a modern energy
complex on the island's southern coast at Vasilikos is already underway, with
several expansions planned for the coming years.
The early phases of the project focus on building up storage capacity and a
transshipment terminal that can serve as an alternative to the more than 200 annual
ship-to-ship transfers that occur in the waters near Cyprus.
Phase I of the VTTI project should conclude in early 2014 and will provide 357,000
cubic meters of storage capacity. Phase II should conclude by the end of 2014,
increasing the terminal's storage capacity to 643,000 cubic meters. A third phase—
scheduled to increase storage capacity to over 850,000 cubic meters—is under
consideration, but the cost (over $150 million) could be prohibitive. Other potential
export options include a pipeline to Greece and floating liquefied natural gas
(FLNG) vessels located offshore.
The pipeline to Greece would allow for direct access to European markets, but the
economics of such an undertaking remain questionable, particularly with the
reduction in the European Union's budget for energy infrastructure projects in the
first half of 2013 and declining demand over the past several years. A FLNG vessel
may be the most economically viable option in the short term, and it could serve as
a
temporary solution should the terminal at Vasilikos prove infeasible for any reason.
Developments in Cyrpus' economy and the country's offshore exploration program
will go a long way towards determining which of these options becomes a reality.

33
12 Import infrastructure
The eastern Mediterranean countries are heavily dependent on petroleum imports,
and limited local production—further diminished by Syria's recent difficulties—
means that the region is likely to need imports for the foreseeable future. As such,
improving the region's connections with other oil-producing areas, like the Middle
East, is a high priority for the region's governments.
Of the two oil pipelines between Syria and Iraq, only the relatively small Ain Zalah
(Iraq)— Suweidiya (Syria) remains operational, but fighting in Syria could threaten
this pipeline as well.
The Kirkuk (Iraq)—Banias (Syria) pipeline sustained damage in the U.S.-led
invasion
of Iraq in 2003, and despite agreements pledging to repair and restart the pipeline,
the current political situation makes this an unlikely possibility.
There are a number of proposed projects for oil and natural gas pipelines in Syria.
One project proposes to build two oil pipelines that would send Iraqi crude to the
Mediterranean coast in Syria, and from there to international markets.
The first of the proposed pipelines would send heavier crudes from northern Iraq
and have a capacity of 1.5 million bbl/d. The second pipeline would ship lighter
grades from southern Iraqi fields along the same route as the former Haditha-
Banias pipeline. Plans call for the second section to have a 1.25 million bbl/d
capacity.
This agreement also includes plans to develop a natural gas pipeline. The natural
gas pipeline will start in southern Iraq and link up with the important energy hub of
Baiji in Iraq, and extend to Baghdad and the Syrian border.
It is unlikely that this proposal will make significant progress until the security
situation in Syria improves. Another proposed natural gas pipeline, originating in
Azerbaijan, should have begun operations some time in 2012, but the conflict in
Syria pushed potential first volumes further into the future. Initially expected to
provide over 90 MMcf/d, delays in the infrastructure buildout have prevented
delivery as of April 2013.
In May 2011, Iran, Iraq, and Syria completed a trilateral agreement arranging for
Iranian natural gas volumes to be sent to Syria via Iraq. Despite the current political
and security environment, all three countries remain interested in pursuing this
project, with the Iraqi Cabinet giving its approval to the $10 billion deal in
February 2013. If successful, the increased volumes from Iran could help close the

34
supply gap that currently exists in Syria, and the additional natural gas could
eventually be sent on to Jordan and Lebanon as well.
While Israel does not currently import petroleum via pipeline, there have been
preliminary discussions about sending Russian oil to the Red Sea. The proposed
pipeline would carry crude oil across the Black Sea to Turkey and then transit the
country and exit at the export terminal at Ceyhan. From Ceyhan the oil would travel
via tanker or pipeline to Israel's port at Ashkelon. Finally, the oil would transit
Israel via existing infrastructure to the Eilat terminal near the Red Sea.
Discussions on this project are preliminary. Jordan is pursuing several oil and
natural gas pipeline deals, notably with Iraq, to help bolster its energy security. One
proposed pipeline would send Iraqi oil from Basra to Aqaba, located on the Red
Sea. If constructed, the pipeline would initially carry up to 1 million bbl/d, with
roughly 150,000 bbl/d available for use inside Jordan via a spur to the Zarqa
refinery. The plan calls for a natural gas pipeline to run along the same route, with
up to 100 MMcf/d
allocated to help meet Jordanian demand.
The total capacity of the pipeline will be 350 MMcf/d, but most of the volumes
will power the pumping stations and power plants used to keep the oil pipeline
operating. There is also a proposal to build a new oil terminal at the port of
Aqaba—which would include storage for both crude oil and products—and
operations could begin in late 2014.
Jordan plans to build an LNG terminal at its oil terminal at Aqaba. The pre-
qualification
submission deadline was May 2013, and Jordan's Ministry of Energy and Natural
Resources suggests that the facility should be ready to receive first volumes in late
2014.
As of April 2013, the proposal called for the use of a Floating Storage and Re-
gasification Unit (FSRU) with a re-gasification output rate of nearly 500 MMcf/d.
In the meantime, Jordan continues to search for partners to fulfill a short-term
contract for delivery of about 150 MMcf/d to the facilities at Aqaba.
To help offset the loss of AGP volumes, Lebanon's Ministry of Energy and Water
proposed building an LNG import terminal at the port of Baddawi. A pipeline
would then connect the incoming volumes to the country's power plants, but there
has not been a final decision as of May 2013.

35
13 Regional issues
Several ongoing issues threaten the exploration, production, and transit of energy
resources in the eastern Mediterranean, especially the security environment,
territorial disputes, and the
macroeconomic climate.
The conflict in Syria has severely limited the country's ability to produce, or export,
oil and natural gas. With fighting intensifying in oil and natural gas producing
regions in 2013, the impact on the country's energy sector will likely increase.
Damage to the country's energy infrastructure has already cost billions of dollars,
and the longer fighting persists the higher the rebuilding costs are likely to be.
Spillover from the fighting in Syria may also affect the energy sectors in Israel,
Jordan, Lebanon, and Turkey, and virtually all plans to use Syria as a transit
country for energy resources are postponed indefinitely.
Other transit options—such as pipelines between Turkey and Israel—will require
multilateral commitments, but relations between several of the transit countries are
poor. For example, Israel and Lebanon are still technically at war, which could pose
a challenge to cooperation in the energy sector.
14 Territorial disputes
Ongoing territorial disputes between several eastern Mediterranean countries could
hinder exploration and development in the region, particularly in the offshore
Levant Basin. Disputes over maritime boundaries jeopardize joint development of
potential resources in the area and could limit cooperation over potential export
options. In addition to negotiating with Cyprus over potential shared resources at
the Aphrodite field, Israel currently has several territorial disputes. A maritime
boundary dispute between Israel and Lebanon could limit development in
prospective regions of the eastern Mediterranean, as over 300 square miles in the
Levant Basin remain disputed by both sides.
While Lebanon and Israel continue to debate the limits of their territorial waters,
Lebanon and Cyprus have an agreement over their shared maritime boundary.
Nevertheless, that agreement was never approved by the Lebanese parliament
because of the ongoing dispute with Israel. There are also uncertainties surrounding
Israel's Gal licensing area, as some reports indicate the area extends into Egyptian
waters. The maritime boundaries have never been formally agreed to in this part of
the eastern Mediterranean, and uncertainty around maritime delineation between
Israel, Gaza, and Egypt limits the attractiveness of operating in the offshore Gaza
area.
Further complicating the issue is the fact that Egypt does not recognize a maritime
boundary with Israel, only the Gaza strip. In addition to the Gaza Marine field, the
Noa field is part of a larger play that crosses into the Gaza offshore area.

36
Should commercially viable energy resources exist in Gaza's territorial waters, a
utilization agreement could be necessary. Even if the political and legal hurdles
surrounding Gaza's offshore areas clear up in 2013, commercial production is
unlikely to begin before 2015. Another complication which has the potential to
deter investors is the Cyprus-Turkey relationship. Turkey disputes the Greek-
Cypriot claim of sovereignty on the island, and maintains an autonomous Turkish
Cypriot exclave on the island's northern territory. There are also simmering
territorial disputes in the offshore territories near Cyprus, with Turkey objecting to
the treaty signed between Cyprus and Egypt as confirmed by the United Nations
Convention on the Law of the Sea (UNCLOS).
In early 2013, Turkey announced that it would begin punishing energy companies
that participate in the energy sector in Cyprus. The first company reprimanded was
Italian company Eni, after Turkey suspended it from its (limited) operations in the
country after participating in the latest Cypriot bidding round. It remains to be seen
how effective these measures will be in deterring investment and involvement in
Cyprus' energy sector.

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