East Med Gas Hub – Future Reality or Pipe Dream?

East Med Gas Hub – Future Reality or Pipe Dream?

Large amounts of discovered gas and substantial exploration upside provide an opportunity for the Eastern Mediterranean to become a significant exporter. With the region increasingly in the spotlight, due to a number of recent discoveries and acreage offerings, we are taking a closer look at the current E&P picture in the littoral states, and some of the challenges they face.

Cyprus

To date, eight exploration wells have been drilled offshore Cyprus, four of which have been successful. Noble Energy drilled one well in 2011 and one in 2013, discovering and confirming gas in the Miocene Tamar sandstones in the Aphrodite Field (estimated at 4.5 Tcf recoverable). Eni targeted the same play in Block 9 in 2014 and 2015 (Amathousa and Onasagorus), but both wells came up dry. In February 2018, the Italian company attempted to drill a further well on the play in Block 3 however, rig operations with the Saipem 12000 drillship were impeded by Turkish military vessels, which prevented the vessel from reaching the wellsite. A future return to the prospect by Eni has been muted.

Blocking the ship was the latest twist in decades-old feuds and overlapping, contested claims in the eastern Mediterranean. Turkey and its vassal state, the Turkish Republic of Northern Cyprus (TRNC), object to the Republic of Cyprus (RoC) drilling in waters that the RoC claims under international maritime law. The RoC ratified the U.N. Convention on the Law of the Sea (UNCLOS) in 1988 and proclaimed its EEZ, in conformity with UNCLOS, in 2004.

Turkey is the only member state of the U.N. that does not recognize the RoC, and it is not a signatory to the UNCLOS. In addition, Turkey considers that a recent agreement between RoC and Egypt, which ratifies the delimitation of their respective economic waters, is null and void.

Just before this hostile episode in the Cyprus-Turkey relations, Total and Eni had some success in chasing the Zohr play in the RoC EEZ. The Total-operated Onesiphoros West 1 well on Block 11 found non-commercial gas in September 2017, whereas the Eni-operated Calypso 1 NFW on Block 6 was announced as a gas discovery in February 2018. Calypso reportedly contains 6-8 Tcf (assumed to be GIIP); Eni plans an appraisal program.

Subsequently ExxonMobil in partnership with Qatar Petroleum, conducted a two-well back-to-back drilling campaign on Block 10 in late 2018/early 2019. While the first well in the campaign, Delphyne 1, failed to find commercial quantities of hydrocarbons, the second well was successful. Glaucus 1 was announced as a gas discovery, with quantities of natural gas estimated at 5-8 Tcf.

While there had been talk of another offshore bid round (the 4th licensing round), the Cypriot cabinet has decided to go a different route this time around. In early October 2018, it invited companies already licensed to explore offshore Cyprus to submit their expressions of interest (EOI) for Block 7 (Herodotus Basin). The invitation concerned companies with concessions bordering the open block, namely Eni (Blocks 6 and 8), ExxonMobil (Block 10), and Total (Block 11), which were given one month to submit their EOIs. Yiorgos Lakkotrypis, Minister of Energy, Commerce, Industry, and Tourism, stated that the government chose to offer the block in this way instead of another licensing round as, “there are particular geological reasons related to the Calypso discovery.” The Minster’s statement, and the fact the Calypso discovery is located in the SE corner of Block 6, suggest that the Calypso structure extends into neighboring concessions. Total and Eni submitted a joint application for Block 7 and negotiations regarding the award of an E&P sharing contract are underway.

Figure 1. RoC demarcated offshore blocks and exploration wells. Also shown are the RoC’s proclaimed and partly agreed EEZ (light blue line), the TRNC’s proclaimed EEZ and outline of demarcated blocks (red line), the outer limits of the continental shelf as claimed by Turkey (orange line), as well as Turkey’s offshore exploration wells.*

Figure 1. RoC demarcated offshore blocks and exploration wells. Also shown are the RoC’s proclaimed and partly agreed EEZ (light blue line), the TRNC’s proclaimed EEZ and outline of demarcated blocks (red line), the outer limits of the continental shelf as claimed by Turkey (orange line), as well as Turkey’s offshore exploration wells.*

Turkey

In Turkey, more than a dozen wells were drilled in the Eastern Mediterranean between 1966 and 2014. None of them were successful, apart from some oil and gas shows. While the shows suggest a working petroleum system, it is not a very good track record. However, it must be said that offshore exploration drilling has been limited to near-shore zones in the Gulf of Alexandretta and the Gulf of Mersin, leaving large areas unexplored.

In an effort to extend exploration in the Eastern Mediterranean, the Turkish state oil company (Türkiye Petrolleri Anonim Ortaklığı – TPAO) has conducted extensive seismic acquisition programs over the last few years. In 2013, TPAO bought an 8-streamer 3D seismic vessel from Polarcus (the “Samur,” rechristened the “Barbaros Hayreddin Pasa”). Since then, it has been acquiring masses of data in the Mediterranean and the Black Sea. In the Eastern Med, the vessel has concluded at least seven separate surveys, with another currently ongoing. Surveys have been acquired to the northeast, south, and southwest of Cyprus, parts of which cover disputed areas.

Turkish officials, keen on reducing the country’s energy imports, have stated on various occasions that the country would take steps toward exploring and drilling in the Mediterranean. TPAO acquired its own drillships, the “Deep Sea Metro II” (now renamed “Fatih”) in late 2017, and the “Deep Sea Metro I” (now renamed “Yavuz”) in late 2018. In addition, it signed a two-well contract with Rowan Companies for the “Rowan Norway” ultra-harsh environment jack-up rig.

In November 2018, “Fatih” and “Rowan Norway” commenced drilling activities, with the former spudding the Alanya 1 well, in the Gulf of Antalya, and the latter spudding the Erdemli North 1 well, in Gulf of Mersin. Erdemli North 1 finished drilling in January 2019 and Alanya 1 in mid-April. Results have not been announced so far for either well. The “Rowan Norway” subsequently moved on to the Kuzupinari 1 location at the entrance of the Gulf of Alexandretta.

Some reports suggest that in the future, TPAO will conduct drilling operations in contested waters around Cyprus. For the ultra-deepwater “Fatih” and “Yavuz” drillships with ratings of 3050m, the water depths in the Eastern Med present no problem, allowing them to drill on any of the demarcated Turkish or TRNC offshore blocks.

Turkey and TRNC signed a continental shelf delimitation agreement in September 2001. Turkey’s claim on the island’s EEZ partly overlaps with the RoC’s blocks 1, 4, 5, 6, and 7. Ankara also supports the TRNC’s claims over RoC’s Blocks 1, 2, 3, 8, 9, and 13, where the self-declared TRNC has demarcated Blocks F and G. Should TPAO start drilling in any of these areas, it could lead to a serious geopolitical – or even military – crisis.

Lebanon

After the conclusion in 2017 of the delayed First Offshore Licensing Round, Lebanon is looking ahead to the drilling of the first exploration well. A joint venture between Total (40 percent), Eni (40 percent), and Novatek (20 percent), the only bidding group in the tender, signed E&P Agreements (EPA) for Blocks 4 and 9 in February 2018. Subsequently, Lebanese authorities approved exploration work plans submitted by the Total-led consortium, paving the way for operations; drilling is expected to begin in Q4 2019.

Total’s stated priority is to drill a first well on Block 4, with a second expected to follow on Block 9. With regards to Block 9, the company said that the consortium is fully aware of the Israeli-Lebanese border dispute in the southern part. However, given that the main prospects are located more than 25km from the disputed area, exploration drilling on the acreage will have no interference at all with any fields or prospects located close to the southern border.

Following a once again delayed approval by the Council of Ministers, Nada Boustani Khoury, Minister of Energy, officially launched Lebanon’s Second Offshore Licensing Round in early April 2019. The acreage on offer includes Blocks 1, 2, 5, 8, and 10, which are located in three distinct major geological zones. Block 1 falls within the Lattakia Ridge zone in the NW of the EEZ, Blocks 5 and 8 are located in the deep Levant Basin in the SW, and Blocks 2 and 10 cover parts of the Levant margin in the NE and SE. The blocks have been chosen to offer a number of different play types, as each zone is characterized by different structural and sedimentological features.

As in the first bid round, interested companies will be required to form a consortium composed of three partners or more, with at least one prequalified as operator. Companies will be able to choose their partners and prepare their bids, which have to be submitted by January 31, 2020. Once bids are submitted, the LPA will evaluate them and prepare a recommendation to the Minister of Energy and the cabinet. Negotiations with successful bidders and subsequent awards are currently planned for late March 2020 and early April 2020, respectively.

Figure 2. Lebanon’s exploration and bid blocks.*

Figure 2. Lebanon’s exploration and bid blocks.*

Israel

Following several offshore gas discoveries in Israel between 2009 and 2013, current activity is focused on bringing the discovered resources onstream. Noble Energy’s Tamar Field (~10 Tcfg 2P) is the only producing offshore field, with Leviathan (~12.5 Tcfg 2P), also operated by Noble, currently under development. Leviathan’s first phase is more than 80 percent complete, on track to deliver first gas by the end of 2019.

Plans are also in place for the development of the Karish and Tanin fields. Operator Energean’s Field Development Plan (FDP) envisages a two-phase approach, with the Karish Field being developed first. The FDP includes the drilling of three development wells at the Karish Field and the installation of a new FPSO around 90 km from the shore. Development drilling started in March 2019, and first gas is planned for 2021. In a second phase, the Tanin Field development will follow, with the drilling of six wells. These will also be connected to the FPSO.

In terms of exploration, Energean is the only operator currently conducting exploration drilling.

In April 2019, it announced that its Karish North near-field exploration well has made a significant gas discovery in the Tamar B and C sands and the well is being deepened to test the hydrocarbon potential in the D4 horizon. Initial gas-in-place is estimated between 1-1.5 Tcf. Energean has drilling options for six further wells in its contract with Stena Drilling. The company has mapped various prospects and leads on the Karish and Tanin leases, as well as on the five exploration blocks it was awarded the First Offshore Licensing Round.

Further drilling in 2019 may be carried out by EDF subsidiary Edison, which operates the 399 Royee exploration license along the border with Egypt. While the first well on the acreage has been postponed on a number of occasions, Delek Drilling’s recent decision to acquire a 24.99 percent stake in the block may give the endeavor renewed momentum. However, drilling will have to start soon, as the license is only valid up to April 14, 2020. At that point the license will have reached its maximum term of seven years.

Israel’s Second Offshore Bidding Round (OBR2), launched in November 2018, may result in additional exploration activity in the country’s EEZ. The acreage offered for bidding in OBR2 includes 5 Zones (A to E) located south of the large gas fields presently being developed offshore Israel. Zones A, B, C, and D include four blocks each, while Zone E includes only three. Each block measures up to 400 sq km. Most of the area offered for bidding was held by various operators in the past, which acquired seismic data and developed exploration prospects that have not been drilled. The closing date for the submission of bids is June 17, 2019. Following a relatively timid response in the First Offshore Bidding Round, with only two companies submitting bids, Israel hopes for better participation this time. ExxonMobil is rumored to have expressed an interest.

Figure 3. Israel’s exploration and production licenses. The Second Offshore bid round zones consist of 19 blocks.*

Figure 3. Israel’s exploration and production licenses. The Second Offshore bid round zones consist of 19 blocks.*

Egypt

As the most mature offshore area in the East Mediterranean, and with gas production in the Nile Delta Basin since the 1970s, the focus in recent years has been the ambition of turning the country into the center of an Eastern Mediterranean gas hub. It has not been smooth sailing, however. The country had been in a net gas deficit since 2014 and began importing LNG in 2015. The two LNG export terminals on the Mediterranean coast, Idku and Damietta, had stood idle. In response, authorities earmarked the fast-tracking of significant gas developments, including BP’s Atoll and West Nile Delta (WND) projects, alongside Eni’s Nooros Field.

Then the 30 Tcfg (in place) Zohr discovery came along in September 2015, at just the perfect time. Nooros was brought onstream in September 2015, WND saw first gas in March 2017, with Zohr coming online in December 2017. Atoll soon followed in February 2018, seeing the total addition of c.40 Tcfg of resource available for production. Concurrently LNG exports at Idku terminal have restarted, albeit modestly at c.500 MMcfg/d. A new gas marketing law was passed in 2017, liberalizing the gas distribution market. In 2018, Noble Energy signed a deal with Dolphinus Holdings to supply gas over a 10-year period (via the East Mediterranean Gas Co pipeline from Ashkelon to El Arish), and a proposed gas pipeline between Cyprus and Egypt was ratified by both countries. LNG imports also ceased in September 2018. The recent EGAS 2018 International Bid Round also saw 13 blocks for tender, the largest offering since 2001. Just three were ultimately pre-awarded, to ExxonMobil (one) and Shell/PETRONAS (two). All three blocks are in the prolific inboard and mature part of the Nile Delta.

No bids were successful in the deepwater frontier acreage where Zohr lies, which brings us to the potential thorn in the side of the gas hub debate. Yes, gas from Cyprus (via Aphrodite) may eventually come to Egyptian shores and possibly also Israeli gas (from Leviathan, Tamar and others). However, it is the indigenous gas supply that could potentially become an issue. Since 2016, there have just been five wildcats drilled in the offshore Nile Delta. Four of the five (Baltim South West 1, Nour 1, Swan East 1, Qattameya Shallow 1) were successful, but have added just around c.2 Tcfg to the resource figures. A maximum of 13 NFWs are planned offshore in 2019, although in reality only around half are likely to be drilled. Coupled with a two-year hiatus between Mediterranean licensing rounds (EGAS 2015 and EGAS 2018 bid rounds), and the delay to the launch of a tender offering for the frontier western portion of Egyptian’s Mediterranean waters, there remains a lot of undrilled acreage in the Nile Delta. In reality there is a need for a ramping up of exploration offshore Egypt in the short term, and ideally the finding of another multi-TCF discovery, in order to both sustain the gas-hungry nation, as well as continue to contribute to the gas hub picture into the future.

Figure 4. Egypt’s exploration and production licenses in the Eastern Mediterranean.*

Figure 4. Egypt’s exploration and production licenses in the Eastern Mediterranean.*

Conclusion

The gas in the Eastern Mediterranean provides risks and opportunities alike for the littoral states. Further successful exploration campaigns and export solutions could significantly help reduce the energy dependence for some of the countries and provide additional revenue to the public coffers. However, even if further significant resources are discovered, it is not guaranteed these will be quickly developed. As shown in the case of Aphrodite and Leviathan, a number of factors can result in long delays.

In addition, complex geopolitics always present a challenge in the Eastern Mediterranean. Should resources be discovered in disputed waters, it could potentially cause further friction in the area, or worse. On the other hand, the common desire to profit from the gas riches in the region might lead to more collaboration. A case in point is the establishment of the East Med Gas Forum, which includes seven members – Egypt, Israel, Greece, Cyprus, Jordan, Italy, and the Palestinian Authority. However, the absence of Turkey and Lebanon highlights the difficult relationships

As mentioned above Egypt’s hopes of becoming a gas hub in its own right in the Eastern Mediterranean are dependent on the country’s indigenous demand and future exploration success. However, taking the significant discovered resources in Israel and Cyprus into account, the idea of Egypt becoming a gas hub is not implausible. Another much discussed possible export route for Israeli and Cypriot gas is the EastMed pipeline from Israel to Italy, via Cyprus and Greece. The current design envisages a 1,300km offshore pipeline and a 600km onshore pipeline, capable of transporting 353 Bcfg per year. The project has been deemed technically feasible and financially viable by IGI Poseidon (a 50-50 joint venture between Edison and DEPA). However, questions remain on whether the gas transported through the pipeline could compete with gas from other sources, like Russia and U.S. (LNG).

* The maps are not an authority on international boundaries.

johannes.sobotzki@drillinginfo.com – Regional Manager Middle East
tom.richards@drillinginfo.com – Regional Manager North Africa

East Med Gas Hub – future reality or pipe dream?

Eastern Mediterranean – the E&P Climate is Getting Hotter in Q4 2018

Eastern Mediterranean – the E&P Climate is Getting Hotter in Q4 2018

 

Following a quiet summer, E&P activity in the Eastern Mediterranean is gathering steam towards the end of 2018. Several significant exploration wells are planned in the near future, and acreage offerings are being prepared across the region.

 

Cyprus

To date, six exploration wells have been drilled offshore Cyprus, three of which have been successful. Noble Energy drilled one well in 2011 and one in 2013, discovering and confirming gas in the Aphrodite field (estimated at 4.5 Tcf recoverable). Eni targeted the same play in Block 9 in 2014 and 2015, but both wells came up dry. In February 2018, the Italian company attempted to drill a further well on the play in Block 3; however, rig operations with the Saipem 12000 were impeded by Turkish military vessels, which prevented the drillship from reaching the wellsite.

Blocking the ship was the latest twist in decades-old feuds and overlapping, contested claims in the eastern Mediterranean. Turkey and its vassal state, the Turkish Republic of Northern Cyprus (TRNC), object to the Republic of Cyprus (RoC) drilling in waters that the RoC claims under international maritime law. The RoC ratified the UN Convention on the Law of the Sea (UNCLOS) in 1988 and proclaimed its EEZ, in conformity with UNCLOS, in 2004.

Turkey is the only member state of the UN that does not recognize the RoC, and it is not a signatory to the UNCLOS. In addition, Turkey considers that a recent agreement between RoC and Egypt, which ratifies the delimitation of their respective economic waters, is null and void.

Just before this hostile episode in the Cyprus-Turkey relations, Total and Eni had some success in chasing the Zohr play in the RoC EEZ. The Total-operated Onesiphoros West 1 well on Block 11 found non-commercial gas, whereas the Eni-operated Calypso 1 NFW on Block 6 was announced as a gas discovery. Calypso reportedly contains 6-8 Tcf (assumed to be GIIP); Eni plans an appraisal program. Further exploration drilling will be carried out by ExxonMobil, with the company planning to conduct a two-well back-to-back drilling campaign on Block 10 in late 2018 to early 2019.

While there had been talk of another offshore bid round, the Cypriot cabinet has decided to go a different route this time around. In early October 2018, it invited energy companies already licensed to explore offshore Cyprus to submit their expressions of interest (EOI) for Block 7 (Herodotus Basin). The invitation concerns companies with concessions bordering the open block, namely Eni (Blocks 6 and 8), ExxonMobil (Block 10), and Total (Block 11), which were given one month to submit their EOIs. Yiorgos Lakkotrypis, Minister of Energy, Commerce, Industry and Tourism, stated that the government chose to offer the block in this way instead of another licensing round as “there are particular geological reasons related to the Calypso discovery.” The Minster’s statement, and the fact the Calypso 1 NFW is located in the south-east corner of Block 6, suggest that the Calypso structure extends into neighboring concessions.

Figure 1. RoC demarcated offshore blocks and exploration wells. Also shown are the RoC’s proclaimed and partly agreed EEZ (light blue line), the TRNC’s proclaimed EEZ and outline of demarcated blocks (red line), the outer limits of the continental shelf as claimed by Turkey (orange line), as well as Turkey’s offshore exploration wells. *

Figure 1. RoC demarcated offshore blocks and exploration wells. Also shown are the RoC’s proclaimed and partly agreed EEZ (light blue line), the TRNC’s proclaimed EEZ and outline of demarcated blocks (red line), the outer limits of the continental shelf as claimed by Turkey (orange line), as well as Turkey’s offshore exploration wells. *

 

Turkey

In Turkey, more than a dozen wells have been drilled in the Eastern Mediterranean since 1966, with the last being drilled in 2014. None has been successful so far, apart from some oil and gas shows. While the shows suggest a working petroleum system, it is not a very good track record. However, it must be said that offshore exploration drilling has been limited to near-shore zones in the Gulf of Alexandretta and the Gulf of Mersin, leaving large areas unexplored.

In an effort to extend exploration in the Eastern Mediterranean, the Turkish state oil company (Türkiye Petrolleri Anonim Ortaklığı – TPAO) has conducted extensive seismic acquisition programs over the last few years. In 2013, TPAO bought an 8-streamer 3D seismic vessel from Polarcus (the “Samur”, rechristened the “Barbaros Hayreddin Pasa”). Since then, it has been acquiring data in the Black Sea as well as the Mediterranean. In the Eastern Mediterranean, the vessel has concluded at least six separate surveys, with another currently ongoing. Surveys have been acquired to the northeast and southwest of Cyprus, parts of which cover disputed areas.

Turkish officials have stated on various occasions that the country will take steps this year toward exploring and drilling in the Mediterranean. To this end, TPAO acquired its own drillship, the “Deep Sea Metro II” (now renamed “Fatih”), in late 2017, and has recently signed a two-well contract with Rowan Companies for the “Rowan Norway” ultra-harsh environment jack-up rig.

While the Fatih drillship is expected to start drilling its first well, Alanya 1, in the Gulf of Antalya in late October or early November 2018, the planned drilling locations for “Rowan Norway” have not been revealed. However, the N-class jack-up has a rating of 120m, so it is likely to be targeting prospects in the aforementioned Gulf of Mersin. Some reports suggest that in future, TPAO will conduct drilling operations in contested waters around Cyprus. For the ultra-deep water “Fatih” drillship with a rating of 3050m, the water depths in the Eastern Mediterranean present no problem, allowing it to drill on any of the demarcated Turkish or TRNC offshore blocks.

Turkey and TRNC signed a continental shelf delimitation agreement in September 2001. Turkey’s claim on the island’s EEZ partly overlaps with the RoC’s blocks 1, 4, 5, 6, and 7. Ankara also supports the TRNC’s claims over RoC’s Blocks 1, 2, 3, 8, 9, and 13, where the self-declared TRNC has demarcated Blocks F and G. Should TPAO start drilling in any of these areas, it could lead to a serious geopolitical – or even military – crisis.

Lebanon

After the conclusion in 2017 of the delayed First Offshore Licensing Round, Lebanon is looking ahead to the drilling of the first exploration well. A JV between Total (40 percent), Eni (40 percent), and Novatek (20 percent), the only bidding group in the tender, signed E&P Agreements (EPA) for Blocks 4 and 9 in February 2018. Subsequently, Lebanese authorities approved exploration work plans submitted by the Total-led consortium, paving the way for operations; drilling is expected to begin in Q4 2019.

Total’s stated priority is to drill a first well on Block 4, with a second expected to follow on Block 9. With regards to Block 9, the company said that the consortium is fully aware of the Israeli-Lebanese border dispute in the southern part. However, given that the main prospects are located more than 25km from the disputed area, exploration drilling on the acreage will have no interference at all with any fields or prospects located close to the southern border.

Prior to the drilling of the first offshore well, Lebanon will open its Second Offshore Licensing Round. The Lebanese Petroleum Administration (LPA) announced preliminary details of the bid round in late July 2018, proposing a launch in late 2018. An unspecified number of blocks will be made available in a competitive and open tendering process, which is expected to conclude towards the end of 2019. At present, out of the ten demarcated offshore blocks, eight are unlicensed.

A four-month period, from January 2019 to the end of April 2019, has been reserved for companies to submit their applications for prequalification. Following this, companies will be required to form a consortium composed of three partners or more, with at least one prequalified as operator. Companies will be able to choose their partners and prepare their bids over a period of at least six months, from May 2019 to October 2019. Once bids are submitted, the LPA will evaluate them and prepare a recommendation to the Minister of Energy and Water and the cabinet by November 2019.

Figure 2. Lebanon’s exploration blocks. All or parts of the open acreage may become available in the Second Offshore Licensing Round. *

Figure 2. Lebanon’s exploration blocks. All or parts of the open acreage may become available in the Second Offshore Licensing Round. *

Israel

Following several offshore gas discoveries in Israel between 2009 and 2013, current activity is focused on bringing the discovered resources onstream. Noble Energy’s Tamar field (~10 Tcfg 2P) is the only producing offshore field, with Leviathan (~12.5 Tcfg 2P), also operated by Noble, currently under development. Leviathan’s first phase is around 64 percent complete, on track to deliver first gas by the end of 2019.

Plans are also in place for the development of the Karish and Tanin fields. Operator Energean’s Field Development Plan (FDP) envisages a two-phase approach, with the Karish field to be developed first. The FDP includes the drilling of three development wells at the Karish field and the installation of a new FPSO around 90 km from the shore. Development drilling is expected to start in Q1 2019, and first gas is planned for 2021. In a second phase, the Tanin field development will follow, with the drilling of six wells. These will also be connected to the FPSO.

In terms of exploration, Energean is the only operator with firm plans to conduct exploration drilling in the near future. It is planning to spud the Karish North near-field exploration well in March 2019, and has the option to drill a further exploration well on completion of the Karish development drilling campaign.

There may also be another offshore bid round. Israeli officials have announced on several occasions that a Second Offshore Licensing round was under consideration, with launch dates between late 2018 and early 2019. Following disappointing results in the first bid round, contractual modifications may be made to make the bid round more attractive. However, no details have been revealed yet.

Figure 3. Israel’s exploration and production licenses. The First Offshore bid round grid may be utilized for a Second bid round. *

Figure 3. Israel’s exploration and production licenses. The First Offshore bid round grid may be utilized for a Second bid round. *

Conclusion

The upcoming exploration activity in the Eastern Mediterranean provides risks and opportunities alike for the littoral states. Successful exploration campaigns could significantly help reduce the energy dependence for some of the countries and provide additional revenue to the public coffers. However, even if significant resources are discovered, it is not guaranteed these will be quickly developed. As shown in the cases of Aphrodite and Leviathan, border disputes and regulatory changes can result in long delays. In addition, should resources be discovered in disputed waters, it could potentially cause further geopolitical friction in the area, or worse.

 

* The maps are not an authority on international boundaries.

Iran E&P – Past and Future: Despite Uncertainties, Oil Industry is Looking Closely

Iran E&P – Past and Future: Despite Uncertainties, Oil Industry is Looking Closely

Following the tentative start of lifting of international sanctions in early 2016, and the government’s announcement of a new tender round for oil and gas projects, Iran is once again demanding investment attention from the international oil and gas industry. Iran has the fourth largest proven oil (157.8 Bbo; BP Statistical Review) and the largest proven gas reserves in the world (1,200 Tcfg; BP Statistical Review). The country is looking for massive foreign investment to update its aging oil and gas infrastructure; this should enable a leap in production to service an increasing domestic demand for gas, and support a rapid rise in oil exports to fund a burgeoning economy.


The country has a long hydrocarbon history, with the first oil discovery in the Middle East made by the D’Arcy Company in 1908 in southwestern Iran (the giant Masjid-i-Sulaiman Field).

Following the 1978 revolution and the expulsion of the Shah, the rights to owning and producing natural resources reverted to the Iranian Government.

Thereafter, the only contracts that the National Iranian Oil Company (NIOC) ever offered were buyback contracts. These contracts are similar to service contracts and require the International Oil Companies (IOCs) to invest their own capital and expertise to develop an oil or gas field.

As per the buyback contracts, upon start of production from a field, operatorship reverted back to NIOC, which then used the revenue from sales to pay back the IOCs their capital expenditure for exploration and development.

The annual repayment rates to operators were based on predetermined percentages of production, as well as a predetermined financial rate of return. IOCs could not obtain any equity stake – this being a fundamental tenet (a philosophy which holds in many oil-rich countries)

1-iran-oil-production-b
Figure 1: Iran oil production and key events

The latest form of buyback contracts was applied in the 1990s and early 2000s, and attracted billions of dollars of foreign investment. But, when the EU and the US enacted sanctions measures in 2011-12, nearly all investors left the country, a move which affected the Iranian energy sector more profoundly than any previous sanctions. In particular, the EU oil embargo as well as sanctions against financial institutions and on shipping insurance affected Iran’s ability to sell crude to all of its customers. In addition, the exit of foreign investment, technology, and expertise limited the country’s ability to expand capacity at oil and natural gas fields and to reverse declines at mature oil fields. NIOC was forced to cut production and shut down some fields, with heavy oil and inefficient fields most affected. As a result, oil production fell from around 3.6 MMbo/d in mid-2011 to around 2.7 MMbo/d a year later, and stayed around the same level until 2015 (Fig. 1). According to the International Monetary Fund (IMF), Iran’s oil and gas export revenues dropped by 47% from US$ 118 billion in the 2011-12 fiscal year to US$ 63 billion in 2012-13.

Since the start of the lifting of sanctions in January 2016, Iran has managed to ramp up production to pre-sanction levels – much faster than many expected. However, it seems that output has hit a natural ceiling in the last few months, with production increasing at a slower pace. The initial rapid increase was attributed to fields and wells coming back online with high pressures, after having been shut-in for years. But the country will struggle to pump more, as undeveloped fields and many of the mature depleting fields need significant investment at a time when Iran remains cash-strapped and unable to finance development from internal capital resources.

Putting aside any OPEC deals with regards to freezing production, Iran’s sixth Five-year Development Plan targets oil production of 4.8 MMbo/d by 2021. In order to reach that goal, the country is hoping to develop oil and gas projects through attracting significant foreign investment under the new Iranian Petroleum Contract (IPC). The IPC was recently approved by Parliament, although this is but one stage in the gestation. In November 2015, Iranian authorities unveiled elements of the new IPC to potential investors at the Tehran Summit, in addition to showcasing 50 oil and gas projects and 18 E&P blocks (Fig.2). Projects presented include onshore and offshore, as well as early- and late-stage projects, with varying degrees of complexity. Proposed production from the development of these oil and gas projects could add around 1 MMbo/d, taking current production of around 3.7 MMbo/d, close to the declared target. According to Minister of Petroleum Bijan Zangeneh, NIOC will initially seek the development of shared fields along its borders (notably borders with Iraq, Kuwait, Qatar, Saudi Arabia and the UAE); also, the completion of the South Pars development project and West Karun oil fields are of top priority.

2-map-of-iran
Source: Drillinginfo database
Figure 2: Map of Iran showing location of 18 E&P Blocks, 50 oil and gas projects and oil and gas fields

Although US companies will likely remain unable to get involved in Iran following the US senate’s decision to extend the Iran Sanctions Act by 10 years, a number of European and Asian IOCs have shown interest for investment. Several have signed Memoranda of Understanding (MoUs) for development studies for various fields, with a view to participate in projects if technical and financial conditions allow. Total has managed to go a step further, when in early November 2016 it signed a Heads of Agreement (HoA) with NIOC for the development of Phase 11 of the South Pars Field – the first such agreement following the signing in December 2015 of the Joint Comprehensive Plan of Action (JCPOA) to lift sanctions. Under the terms of the HoA, NIOC and the project partners (Total – op. 51%; Petropars 19.9% and CNPC 30%) will conduct exclusive negotiations to finalise a 20-year contract in accordance with the technical and economic terms established in the HoA, within the framework of the new IPC.

However, even with these strong signals regarding investment interest in the opportunities available in Iran, significant and wide-ranging challenges and risks remain, both above-ground and below-ground. These include remaining sanctions, banking and insurance issues, along with perceptions of corruption and lack of transparency (Iran is ranked 130 out of 168 countries in Transparency International’s 2015 corruption perception index). Political risks remain high too, with the country having poor relations with a number of neighbours in the Middle East, as well as further afield. Companies will have to assess how entering Iran might affect their business elsewhere. The principal risk for any company establishing operations in Iran, especially following the recent US elections, is the uncertainty surrounding future US-Iran relations and the potential for renewed sanctions under the snap-back provisions in the nuclear deal.
In any case, it remains to be seen how attractive the terms of the new IPC really are. The finer details are not yet available, but it is expected that the contract will be an improvement on the existing buybacks, hence presenting a new opportunity to the IOCs. Under the new contract terms, it is certain that companies will still be unable to own reserves; however they will be able to establish JVs with NIOC, or its subsidiaries, to manage the entire life-cycle of a project. Companies will have a longer time period, of between 20 to 25 years to explore, develop and produce from a field, with the possibility to extending it to the Enhanced Oil Recovery (EOR) phases. Fiscal terms are also understood to have been reworked.

Nevertheless, at the recent 4th Iran Europe Oil, Gas & Energy Summit in Berlin (attended by Drillinginfo), it was suggested that while improvements have been made, they might not be as advanced as many are hoping. The launch of the IPC has been postponed several times as rivals of President Hassan Rouhani resisted any deal that could end the buy-back system, and many minor and major changes have been made over the last year to appease political opponents.

Despite the investment difficulties, the opportunities in Iran make it compelling for Non-US companies to enter or re-enter the country. At a time when oil prices are down to levels not seen for a decade, IOCs need to look for exploration and production opportunities that require comparatively little capital and operational expenditure. As such, projects in Iran present great prospects – with costs to produce a barrel of crude in Iran estimated at around US$ 9 (Rystad Energy) compared to an average of around US$ 9 in Saudi Arabia, around US$ 35 in Brazil and around US$ 44 in the UK.

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Iran Oil: Post-Sanctions Opportunities and Challenges

Iran Oil: Post-Sanctions Opportunities and Challenges

Iran, a country boasting the fourth largest oil and the second largest gas reserves in the world, has currently become one of the most prominent news topics – for example today’s election news affirming the shifting of political power to the moderate and reform candidates.

From the oil and gas industry point of view, the lifting of international sanctions provides the country, as well as International Oil Companies (IOCs), with opportunities at a time when oil prices are down to levels not seen for a decade. Although there is every likelihood that prices will rebound, the drivers of demand and supply indicate that this may not happen for some time.

The IOCs are hurting, reflected largely by their cut back in dividend as well as profit falls and job cuts. Under these circumstances, IOCs need to look for exploration and production opportunities that require comparatively little capital and operational expenditure. As such, Iran presents itself as a great opportunity – with costs to produce a barrel of crude in Iran estimated at around US$ 12 compared to an average of around US$ 9 in Saudi Arabia, around US$ 36 in the USA and around US$ 52 in the UK. Provided the IOCs are willing to accept the risks and challenges that arise with investing in Iran, the offering of about 18 E&P blocks and 50 oil and gas projects worth US$ 185 billion by 2020 under the new ‘Iranian Petroleum Contract’ (IPC), might just be the need of the hour.

On the other hand, Iran itself seems anxious about the incoming investment, as it is looking to update its aging oil & gas infrastructure, in order to increase production to meet the rising local demand alongside helping fund government spending. An initial foreign investment of around US$ 25 billion is targeted and several leading European E&P companies (BP, Eni, Repsol, Shell, Statoil, Total) are believed to have been in discussions. In late September 2015, the Minister of Petroleum, Bijan Zangeneh, declared the path chosen by the country by announcing that Iran will not hold back its oil production once economic sanctions are removed and that the country’s crude output will reach an ambitious 4.2 MMbo/d by the end of 2016. Crude oil production currently stands at around 2.85 MMbo/d and in an effort to reclaim its lost share of exports, Zangeneh anticipates the country taking back a market share of more than 1 MMbo/d. More conservative estimates, however, suggest an increase in production of between 600,000 bo/d and 1 MMbo/d within six months of the lifting of sanctions – subject to the negotiations ongoing for freezing oil production.

iran oil fig 1
Map of Iran showing location of 18 E&P Blocks, 50 oil and gas projects and oil and gas fields (Source: Drillinginfo database)

The country has gone through a series of tumultuous events, the more important being the CIA’s 1953 coup displacing the democratically elected Prime Minister Mohammad Mosaddeq, followed by installation of Mohammad Reza Pahlavi (Shah of Iran) which ultimately led to the Iranian Revolution in 1979, followed by an eight-year-long war with Iraq and various sanctions, which hit the country worst in 2011. Having faced such, it is surprising for many to see the country still being a dominant player in the Middle East and competing with Saudi Arabia. This very point makes the country hugely important – not only regionally but internationally – because a freely trading Iran, which will ultimately make the country financially secure, can reasonably change the power dynamics of the region, the dominance of Saudi Arabia and the fundamentals of relative stability left in the region.

Iran has a long oil history – the first oil discovery in the Middle East was made by the D’Arcy Company in 1908 in southwestern Iran (the Masjid-i-Sulaiman Field). Following the revolution, the right of producing and owning natural resources was given to the Iranian Government and the only contracts that the National Iranian Oil Company (NIOC) ever offered were buyback contracts. These contracts were similar to service contracts and required the IOCs to invest their own capital and expertise to develop an oil or gas field. As per the buyback contracts, upon commencement of production from a field operator-ship reverted back to the NIOC, which then used the revenue from sales to pay back the IOCs their capital expenditure. Additionally, the IOCs did not get any equity in the fields and the annual repayment rates to the companies were based on predetermined percentages of the field’s production, as well as the predetermined rate of return.

The latest form of buyback contracts attracted billions of dollars of foreign investment in the 1990s and early 2000s, until nearly all investors left the country when the EU and the US enacted measures in 2011-12 that affected the Iranian energy sector more profoundly than any previous sanctions. As a result, oil & condensate exports in 2012 fell by around 1.0 MMbbl/d compared to 2011 and stayed around the same level until 2015. According to the International Monetary Fund (IMF), Iran’s oil and gas export revenues dropped by 47% from US$ 118 billion in the 2011-12 fiscal year to US$ 63 billion in 2012-13.

iran oil fig 2

The new Iranian Petroleum Contract (IPC), which contains terms similar to a Production Sharing Agreement (PSA), was unveiled at the Tehran Summit in November 2015. With the new IPC, the Government is trying to increase the country’s attractiveness to foreign investment in the industry, in order to develop infrastructure and to boost production.

Although the finer details of the IPC are yet to be finalized, it is expected that the contract will be an improvement on the existing buybacks, presenting a new opportunity to the IOC’s. Under the new contract terms, companies will remain unable to have ownership of reserves, but will be able to establish JVs with NIOC, or its subsidiaries, to manage the entire life cycle of a project. Companies will have a longer time period of between 20 to 25 years to explore, develop and produce from a field, with the possibility to extending it to the Enhanced Oil Recovery (EOR) phases. Fiscal terms are also understood to have been reworked.

The auctioning of 50 oil and gas projects and 18 E&P blocks – aimed at doubling the country’s crude oil output from 2.85 MMbo/d to 5.7 MMbo/d – is expected to be held in May 2016 and will provide IOCs with an opportunity to help re-balance their portfolios and books and to remain competitive in a low oil price environment. The licensing round will include onshore and offshore, as well as early and late stage projects, with varying degrees of complexity.

At a time when companies are looking to cut capital and operating expenditures, the low-cost barrels that are going to be available make an entry / re-entry in Iran look very attractive. However, entering Iran will require careful consideration of the challenges and risks, below, as well as above ground. Political risks remain high too, with the country having poor relations with a number of neighbors in the Middle East, as well as further afield. Companies will have to assess how entering Iran might affect their business elsewhere. However, the major risk for any company establishing operations in Iran is the potential of renewed sanctions, should the country fail to adhere to the agreements made regarding its nuclear program.

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