Kenya goes alone with first oil targeting 2021 - plays catch-up with Uganda

Kenya was left at the pipeline “altar” in 2016 when Uganda decided to export its crude via a Tanzanian pipeline instead. The years of work around a joint Ugandan-Kenyan pipeline went to waste as the two countries could not agree on the development with security as well as political factors hindering co-operation between the two countries.

Kenyan oil discoveries in the Lokichar Basin had been left in limbo with no export plan in sight. However, over the course of 2017, Kenya realised it had to go it alone and started evaluating plans for a standalone export pipeline. In October 2017 the Lokichar owners, Tullow, Africa Oil and Maersk, initiated a study including FEED for the proposed pipeline. The ministry announced at the time that it was planning for an 820km pipeline between Lokichar and Lamu at a cost of USD2.1 billion to be completed in 2021.

The pipeline is expected to be FID-ed in 2019 and it has been reported that significant work has been carried out on the routing which has to deal with the complications of security risk, avoiding nature reserves, population displacement, elevation as well as cost.

Tullow’s commitment to the pipeline was followed by a commitment by Total in January 2018, which appears to have been part of the deal to obtain approval for taking over Blocks 10BA, 10BB and 13T from Maersk as part of the Maersk Oil acquisition.

On 7th February, Tullow announced that it progressing Kenya further with plans for an initial small scale development of 210mmbbl with peak production of 60-80mbopd. This would be the first phase of a wider development which originally had a 560mmbbl 2C resource number and peak production of 100mbopd+.

The Tullow-led JV will develop the Amosing and Ngamia fields as an initial 210mmbbl “Foundation Stage” which will include the export pipeline to Lamu, allowing for earlier FID than a full scale project. Foundation Stage upstream capex is estimated at USD1.8 billion and pipeline capex is estimated at USD1.1 billion – this is significantly below the USD2.1 billion estimate announced last year and the USD2.7-3.0 billion a few years ago (for the Kenyan leg only).

This export infrastructure is critical for monetising the discoveries in the Lokichar and also unlock remaining exploration potential in Kenya along the pipeline route. Tullow is targeting an FID in 2019 with first oil in 2021/22.

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Kosmos' end of a winning streak with dry well at Requin Tigre

Kosmos Requin Tigre prospect was announced dry this morning. This was a "make it" well that had the potential to add 60bcf of gas in the Senegal/Mauritania trend and would have increased total gas discovered in the basin to over 100tcf. However, this dry well constrains Kosmos' growth in the basin with no further exploration drilling in area for now. The drillship will now proceed to test two oil prospects offshore Suriname commencing in early Q2 2018.

With three dry wells in a row, Requin Tigre, Hippocampe and Lamantin (the last two targeting liquids), Kosmos shine as an exploration company is now wearing off. It now follows in the footsteps of other E&Ps such as Tullow, which was once an exploration-led company but increasingly focussed on delivering on its projects and commercialising an inventory of discoveries.

For now, it appears that Kosmos' West African story is finished.

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Mitsui victory for AWE battle?

AWE’s board has recommended Mitsui’s all cash bid of A$0.95/share which was received on 28^th January. This superior offer follows a heated battle since the end  of last year.

• November 2017: CERCG cash bid of A$0.71/share conditional on due diligence, rejected following AWE’s assessment that it undervalued the company
• December 2017: CERCG revised cash offer of A$0.73/share
• December 2017: Mineral Resources scrip offer at A$0.80/share
• December 2017: Revised Mineral Resources cash and scrip offer at A$0.83/share – recommended by the AWE board on 21st December
• January 2018: Mitsui all cash offer at A$0.95/share

The Mitsui bid is comparatively clean – all cash, no further due diligence and FIRB approval already obtained. As Mineral Resources did not come back with a superior offer by the deadline of 2^nd February, AWE has entered into an implementation deed with Mitsui with a recommendation to shareholders by the AWE board. Mitsui has a right to match any superior offer and there is a break fee if AWE changes its recommendation.

Mitsui is a natural buyer of AWE and its assets with an established history in Australian E&P. It is in the Northwest Shelf LNG project with Mitsubishi on the west coast, in offshore Victoria gas and Queensland Coal Bed Methane gas project.

Absent any superior offers, Mitsui offer documents are planned to be dispatched to shareholders on Monday 12th February with the offer period for shareholders to accept the offer open until 20th March. The offer required 50.1% acceptances from shareholders to proceed.

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Israel capital cycle: Noble sells down Tamar to fund Leviathan

Noble Energy is divesting 7.5% of its 32.5% interest in the Tamar field for USD800 million. This will reduce Noble’s interest to 25% as required by the Israeli government’s competition requirements. The buyer is Tamar Petroleum who will pay for the acquisition with USD560 million in cash and 38.5 million shares in Tamar Petroleum. The divested interest represents 62mmcfpd of production in 2017 and reserves of 500bcfe.

Noble intends to sell-down the share portion of the consideration over the next few years. After capital gains tax on the USD800 million, Noble will net around USD615 million which it will use to help cover upcoming development expenditure on the giant Leviathan development. The spend in 2018, net to Noble, is USD600 million in 2018 and USD425 million in 2019.

Noble continues to be a major player in the Eastern Mediterranean and advances its contracting efforts on Leviathan where it has signed up 525mmcfpd is gas sales contracts with another 1,100mmcfpd being negotiated.

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EnQuest agrees Thistle decommissioning with BP

Following on from last year's acquisition from BP, EnQuest has agreed with BP to undertake the management of the decommissioning activities for Thistle and Deveron.

EnQuest will receive USD30 million in cash for management of the decommissioning and for taking on 3.7% of the gross decommissioning costs of the Thistle and Deveron fields, subject to a cap of USD80 million. EnQuest estimates its exposure to costs is currently less than the cash being received.

EnQuest also has an option, exercisable over a 12-month period, to receive a further USD20 million in return for taking on a further 2.4% of the gross decommissioning costs of these fields, subject to a cap of USD59 million.

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Endeavour endangers Alba sale for Statoil and Mitsui

Statoil and Mitsui started marketing their stakes in the Alba heavy oil field in the North Sea at the end of 2017. The field is located in a complex reservoir and developed from a steel platform tied to a floating storage unit.

The field has been marketed by partner Endeavour before without success. Endeavour put its stake up for sale in 2015 but failed to attract sufficient interest.

Sources have revealed that interest in the current sales effort is also thin with potential buyers raising a number of concerns:

Non-operated stake Both Statoil (17%) and Mitsui (13.3%) hold non-operated stakes. The operator is Chevron with 23.4%. This limits the new owner’s ability to implement efficiencies, especially as neither on their own or combined have a controlling stake. Chevron is a decent operator, but being a “major” inevitably means inefficiencies and costs creeping in. This is why the likes of BP have passed assets onto more nimble E&Ps who they know can run assets more efficiently.

Limited upside The field has been producing since 1994 and approaching end of life. Production could continue into the late 2020s but at increasingly insignificant volumes. In 2016, Alba produced at 15.3mbopd which compares to a peak of 80-90mbopd in the early 2000s. In 2014, Chevron undertook a 4D seismic survey to identify infill targets – although infill drilling could continue, Chevron has not committed to a full drilling programme of the prospects. Furthermore, Chevron is divided on its view of the North Sea portfolio – it is a good collection of assets generating good cash flow for North America but at the same time focus is turning to the US onshore. With Chevron’s new CEO Mike Wirth coming onboard in February and his background in downstream, the desire to put capital into the North Sea remains in question.

Decommissioning With a large number of wells and a steel platform, decommissioning will be a complex and high cost exercise – no small endeavour for a buyer to take on. Costs are currently estimated at c.USD750 million in real terms and could go up with the blanket of decommissioning activity coming up in the North Sea.

Endeavour bankruptcy Endeavour is the largest partner at 25.7%. Its US parent company entered into financial restructuring and the UK business is under creditor protection. The UK subsidiary Endeavour Energy UK Limited holds the interest in the field and still has debts of close to USD1 billion. The UK business is in default and the lenders, primarily Credit Suisse, have so far have extended repayment deadlines. However, if the lenders pull the plug on the business in light of Alba continuing to be loss making (per latest financial statements), then the remaining partners in the field will be compelled to take on additional stakes in Alba pro rata. This is a risk to a potential new owner and would increase exposure to future capex and decommissioning.

From the buyer feedback, it is clear why Statoil and Mitsui want to exit the asset. For Statoil, the UK North Sea is becoming less of a focus apart from its remaining large developments. For Mitsui its UK strategy appears to be retreat. Whether a sale goes ahead or not remains to be seen.

UPDATE 24 March 2018: Bidders pull out of Alba sale by Statoil and Mitsui

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Kurdistan payments and new oil sales agreements

Kurdistan producers receive payment for October sales
Gulf Keystone signs new oil sales agreement with the KRG

DNO has reported a payment of USD54 million for Tawke production from the Kurdistan Regional Government. This is in respect of October oil deliveries. The payment will be shared between the licence partners WHO 75% and Genel 25%. Although there is a lag in payments between production and receipt, this is viewed as normal with October sales invoiced in November and approval by the Government in December with payment the following month. The continued stream of payments demonstrates the importance of oil exports to Kurdistan, especially following the independence referendum last year which threw doubt on the region's ability to carry on managing its finances.

In December, DNO reported production from its two field on the Tawke PSC averaged 110mbopd. Production is expected to climb from these levels as operations ramp up at the Peshkabir field. With higher oil prices and continued payment, DNO could begin to undertake infill drilling on the PSC later this year.

Last week, Gulf Keystone also announced that it had agreed a new PSC-linked oil sales agreement with the Government for its Shaikan crude, reinforcing continued progress in the region around oil company activities. Under the agreement, the KRG agreed to buy crude at Brent less USD22/bbl reflecting a quality discount and transportation costs. Kurdistan crude has historically been marketed following a SOMO (Federal Iraq’s State Organisation for marketing of Oil) formula which provides for a discount of c.USD0.4/bbl of API quality. With Shaikan crude at 18˚ (vs. Brent 38˚) suggesting a USD8/bbl discount plus pipeline export costs to Ceyhan estimated at USD4/bbl, the USD22/bbl discount agreed with the KRG seems to be extremely high. This is likely due to additional discounts on Kurdistan originating crude, where the international buyer community could be thin, resulting from political sensitivities of taking on crude from the disputed region.

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VNG to evaluate options for its Norwegian E&P business

As widely expected, VNG's owner EnBW is looking for a partner or buyer for its E&P business VNG - full press release below.

As part of VNG Group’s strategic programme “VNG 2030+”, VNG – Verbundnetz Gas Aktiengesellschaft (VNG AG) will explore strategic options for its oil and gas exploration and production business in Norway and Denmark, VNG Norge AS (“VNG Norge”). As VNG AG sees long term value creation potential in the E&P-business, the main objectives are to maximise the value of VNG Norge and to support further growth to position the shareholding as a leading player on the Norwegian Continental Shelf together with a strategic partner.

VNG Norge is a full-cycle Norway-focused E&P company, with a solid growth portfolio underpinned by the operated flagship asset “Fenja”, one of the largest Norwegian discoveries in recent years (formerly “Pil”), which is proceeding according to plan, sanctioned by VNG AG and fully supported by all shareholders of VNG AG. Overall the company holds interests in 32 licenses in Norway, two in Denmark and participates in five producing fields and in three field developments at the end of 2017.

Source: https://www.vng.de/en/news/vng-ag-evaluate-options-maximise-value-its-norwegian-ep-business

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Norway awards record 75 exploration licences in 2017 APA

Norway has awarded a record number of 75 exploration licences in the APA 2017 licensing round to 34 companies. The licences comprised 45 in the Norwegian North Sea, 22 in the Norwegian Sea and 8 in the Barents Sea.

Statoil was the biggest winnder with 31 awards. Supermajors ConocoPhillips, ExxonMobil, Shell and Total also picked up licences.

Of the E&Ps:

• Aker BP was the winner with 23 licences (14 as operator)
• Lundin has been awarded 14 licences (5 as operator)
• DNO has been awarded in 10 licences
• Faroe Petroleum has been awarded 8 licences (four as operator)
• Cairn Energy has been awarded 5 licences

The Annual Predefined Areas or APA round was introduced in 2003 to encourage exploration and development of discoveries near existing infrastructure. Across all the awards this time, there are three licences with firm drilling commitments, with the remaining having drill or drop options in the next 12-24 months.

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Canadian LNG: Wrong place wrong time for Petronas

Petronas entered Canada in 2011 to build a full upstream gas and LNG business. It did this in the face of declining domestic production and need to source international gas for both domestic consumption and its LNG trading portfolio. It made a move in June 2011 to partner with Progress Energy for CAD1.1 billion by agreeing to fund the majority of future drilling and capital expenditure on the company’s vast acreage position in the Montney play. In 2012, Petronas decided to acquire the whole of Progress Energy for CAD5.3 billion.

Petronas had a fully-fledged plan – consolidate acreage in the Montney (which it did by acquiring Talisman’s portfolio in 2013 for CAD1.5 billion), work up a plan to develop the gas in the ground and send it to an LNG plant, and bring in partners to help fund the hefty project once the plan was in place. In 2013, it appeared that Petronas was making good progress going out to award FEED contracts for the project. Between 2013 and 2015, Petronas brought in a string of Asian partners who were all hungry for more gas to satisfy their domestic appetites and keen to develop a gas and LNG project with Petronas. By the end of 2014, the ownership of the so called Pacific Northwest LNG project was Petronas 62%, Indian Oil 10%, Sinopec 10%, Japex 10%, China Huadian 5% and Petroleum Brunei 3%. However, the project then began hitting a series of roadblocks.

LNG was a completely new industry to Canada and the country did not have the regulatory framework in place – environmental policies and new taxes were being made up as Petronas progressed its project. There was much bickering and negotiations with the provincial and federal governments – with so many moving parts outside of its control, Petronas and its partners could not finalise its investment decision.

There was also strong opposition from environmental groups and the First Nations. Although their agendas overlapped on environmental protection and land preservation, the two groups did have opposing objectives. Some environmental groups wanted the project shelved altogether, whereas the First Nations wanted to share in the economic benefits with suitable protections for their lands.

The straw that broke the camel’s back came in September 2016 when the federal government granted environmental approval, but attached 190 conditions that would require the advanced project to be re-engineered and relocated to meet new onerous environmental requirements. The Pacific Northwest partners went back to the drawing board and even considered moving the liquefaction facility to another island and sourcing power from an hydroelectric plant rather than self-generate from gas. By July 2017, the partnership announced that it was pulling the plug on Pacific Northwest LNG and began looking for buyers for its Montney acreage.

Pacific Northwest LNG had become too expensive and uncompetitive compared to US Gulf Coast LNG projects. While Pacific Northwest was struggling to progress things along, the US had clearly overtaken Canada on LNG exports and were able to do things more cheaply. The US had extensive pipeline infrastructure to carry gas to the coast for export, existing LNG import terminals which could be flipped for exports by adding liquefaction facilities and moved quickly on the regulatory front to give companies and investors certainty on their LNG projects.

Cost stack for pre-FID LNG projects delivered to Asia
Source: Wood Mackenzie

Petronas took a brave step in opening up a new LNG industry in Canada, a developed country it thought would be business friendly with the protection of the law. Clearly the advent of LNG overwhelmed Canada and it was not yet ready to handle such complex projects. Petronas was the unlucky company that found itself in the wrong place at the wrong time.

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Tullow ventures into Peru

Tullow has farmed into Karoon Gas' 35% of Block Z-38 in Peru. This reduces Karoon Gas' interest to 40% with Pitkin Petroleum being a 25% partner.

Tullow has acquired the 35% interest in return for:

• Funding 43.75% of the cost of the first exploration well, capped at US$27.5m (for 100% cost of well) after which Tullow will pay its 35% share; and
• US$2m payable upon completion with US$7million payable upon declaration of commercial discovery and submission of a development plan to Perupetro.

Karoon has identified two prospects, Marina and Bonito, with a net unrisked prospective resources of 1.7bnbbl. Tullow will now drill the Marina prospect. Karoon Gas' 75% interest is still subject to completion of farm-in obligations which includes funding of two exploration wells.

The block has been in force majeure since 2014 and once lifted, Karoon Gas will have 22 months to complete its drilling commitment. Although the timing of drilling remains uncertain, the block is covered by high-quality 3D seismic and Marina is a potential candidate for drilling in 2019.

Separately, Tullow has concluded negotiations with Perupetro to acquire a 100% stake in offshore Blocks Z-64, Z-65, Z-66, Z-67 and Z-68.

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US LNG: a snapshot of where things stand in 2018

US shale has been a game changer for the gas markets. Often overshadowed by oil story, US gas production is the unloved sibling of oil – oversupplied, low prices, unprofitable and sometimes an unwanted by-product of oil production in the form of associated gas.

However 2017 came to demonstrate the vast potential for US gas and a complete change in direction with the country becoming a net exporter of gas for the first time. This started with first export from Sabine Pass LNG in 2016 which has now grown to four liquefaction trains with trains 5 in the works.  LNG export capacity could reach 8-9bcf/d in 2020 up from the current 2bcf/d, with additional facilities already under construction:

• Cove Point commenced feed gas at the end of 2017
• Elba Island Phase I will come onstream in H1 2018 and Phase II in H1 2019
• Freeport train 1 is planned for operation in 2018 with subsequent trains coming online throughout the rest of 2018 and 2019
• Corpus Christi and Cameron will also come online towards the end of this decade

Source: EIA

US LNG has been somewhat of a disruptor – it has brought destination flexibility and shorter-term procurement to the market that was once characterised by entirely long-term, oil-price linked offtake. This will shake up the market place and how LNG sourcing will evolve is yet to be understood.

Asia is slated to be the big winner with this extra source of gas with South Korea, Japan and China being the largest importers. This is all helped by the recent expansion of the Panama Canal, enabling LNG from the US east coast to Asia with a cheaper and 11 day shorter journey time. This puts into question whether any US west coast and Canadian LNG projects will take off – very likely no in the near-term. The east coast’s proximity to upstream gas, existing pipeline infrastructure to get gas to liquefaction plants and adapted docks means it remains an advantageous location to host LNG terminals.

Related post: Canadian LNG: Wrong place wrong time for Petronas

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Forties Pipeline System reopens in time for the New Year

On 11^th December, INEOS the owner of the Forties Pipeline System, had discovered a hairline crack in the pipeline at Red Moss near Netherley. The crack continued to grow upon monitoring and the entire system was subsequently shutdown. INEOS announced this morning that the repairs are "mechanically" complete with the system being restarted - export rates should resume to previous levels around the new year.

The system carries c.450mbbl/d of production from the North Sea to the Kinneil processing facility in Scotland. The 235 mile pipeline links more than 80 North Sea fields and delivers almost 40% of UK North Sea production. Upon its outage, Brent crude jumped to USD65/bbl signalling the importance of North Sea production to the global oil markets.

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Amerisur putting plans in motion

Amerisur is a story of slow and steady wins the race. The company had targeted 10mbbl/d to be reached a few years ago - with current production only at c.7mbbl/d, this target has clearly fallen by the wayside. Amerisur has learnt, and is continuing to learn, that doing business in Colombia (and Ecuador) is not straightforward and getting necessary government approvals can take months and sometimes years rather than weeks - the OBA pipeline being a case in point. Layer on top of this the local community liaisons and security issues in the Putumayo Basin, one begins to understand the impediments to Amerisur's progress over the past years.

Nevertheless the Amerisur team has managed its portfolio and navigated the winding road of being a Colombian E&P carefully and is now one of a small handful of successful producers in the Putumayo Basin. As well as building up its asset base beyond what was effectively a single asset company in Platanillo, Amerisur has made good progress on the exploration and appraisal front which will set the company up for the longer term.

Amerisur is a company we continue to watch with interest and with enough patience, is a rare success story that will materialise over time.

Drilling Update

North Platanillo
At the start of 2017, Amerisur had success at Plat-22 encountering 43ft of U-sands and flowing at 800bbl/d, extending the Platanillo field north. This was followed by Plat-21 which derisked the extension further testing 430b/d.  Plat-25 came in below expectations, but was sidetracked to target better reservoir quality and additional pay thickness, and was brought on production at 180 bbl/d. In December, Plat 27 encountered net pay of 12ft in the U and 9ft in the T sands. This success could add up to 10mmbbl of reserves.

In 2018, drilling activity on Platanillo switches to the N sand stratigraphic play with the upcoming planned three-well programme targeting the 18.8mmbbl N Sand Anomaly (expected to start in Q1 2018).

Mariposa (CPO-5, Amerisur 30%, ONGC 70%)
Mariposa-1 was successfully drilled in May 2017 which flowed at 4.6mbbl/d 41API light oil. The well was drilled to a total depth of 11,556ft with an indicated 120ft net pay in the L3 Sands. The well is now producing around 3,200b/d (gross) on Long Term Test on a restricted choke.

Further drilling is planned on the block in 2018 (including Indico-1 and Sol) which could add material reserves to the portfolio.

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Premier's Christmas present

Premier Oil announced today that the Catcher field achieved first oil on 23^rd December, on schedule and almost 30% below budget. Initial production will be c.10mbopd as gas processing and water injection modules are commissioned. Production will be ramped up in phases through H1 2018 as the Varadero and Burgman fields are brought onstream increasing production to 60,000mboepd (gross).

The Catcher partners are Premier Oil (50% operator), Cairn Energy (20%), MOL (20%) and Dyas (10%). For Premier Oil, Catcher will account for c.25% of 2018 production with successful ramp up of the field important to deleveraging the balance sheet next year. For Cairn, this will diversify the production base following first oil at Kraken (29.5% interest) earlier this year.

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Kosmos: An unfinished West African story

Kosmos has had a busy 2017 chasing a high risk high reward oil play and working up its Senegal/Mauritania gas resources.

In the second half of the year Hippocampe and Lamantin both came in dry ending the company's campaign for higher value oil. It can now focus on developing the c.40tcf of gas found at Tortue, Teranga, Yakaar and BirAllah. It has hopefully found the right partner in BP who farmed-in in late 2016. Although not generally seen as a big gas player, BP is increasingly focussed on gas as it turns to the future - the major is shifting to investing in large scale gas projects and look to increase global production to c.60% gas from the current c.50%.

When we met with Kosmos earlier this year, they noted that they had their choice of Supermajor when seeking a partner with attractive offers from the usual suspects. Kosmos see BP as the partner who is fully aligned with them, with BP going as far as setting up Senegal/Mauritania a separate profit centre to demonstrate their seriousness.

The West African gas play continues to be derisked with the 60tcf Requin Tigre prospect being drilled and results expected in early 2018 which would increase gas resources in the basin to c.100tcf if successful. This could add a significant leg to a multi-phase LNG project. However, a dry well would dampen the high mood in the basin with the growth outlook more constrained.

FID around Tortue is planned in 2018, although success at Requin Tigre could change the development order with Tortue (which straddles the Senegal/Mauritania border) delayed. It should also be noted that gas would come onstream at a time of a gas glut with LNG in North America, East Africa and Australia coming onstream.

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AWE: an unexpected union

The AWE Board has unanimously recommended a revised bid by Mineral Resources (“MinRes”). The offer terms are A$0.415 in cash and between 0.0198 and 0.0277 MinRes shares per AWE share. The exchange ratio will depend on the VWAP for the 10 days prior to the scheme vote. The previous offer was a full scrip offer at A$0.81.

This values the offer at an implied price of c.A$0.83 per AWE share and will be implemented by a Scheme of Arrangement, which will require 75% shareholder approval with the shareholder meeting to be held in mid-April 2018. Shareholders will have the option to receive 100% cash or 100% scrip subject to scale back to ensure total transaction consideration is 50% cash and 50% scrip.

After four years of “tug-of-war” between AWE and various bidders (Senex in 2013, Lone Star in 2016, CERCG in 2017 and various others which have not been made public), it looks like the AWE Board have finally selected a suitor. Although AWE could have gone down the “do it alone” route, the uncertainty on timing of new production from Waitsia and/or Ande Ande Lumut cast a shadow over the company’s story and its future with a declining production profile.

MinRes immediately answers the question of future gas offtake: Min Res has a requirement for c.30TJ/d of gas based on current plans to convert all of its internal power generation to gas fired plant and to use as the primary fuel source for its Lithium/Graphite related downstream processing plants. This gas requirement is expected to grow with the likely conversion of 26 mine sites (growing to 40) to gas as well as potential for more downstream projects. The rationale for MinRes acquiring AWE is so that it can lock in its gas costs for the next 20–30 years. Min Res also plans to provide gas to its mining clients under long-term gas supply contracts.

AWE shareholders will buy into a new story of a miner/mining service provider with its own growth story. The variable cash and scrip components will likely promote higher acceptances and will provide a way for AWE shareholders to fully realize their investment if they choose not to go into MinRes.

MinRes offer is c.14% above the previous all cash A$0.73 bid from CERCG – MinRes would have the right of response to match any competing offer if CERCG or another party came back with a superior proposal. The deal is subject to a break fee of A$5.2 million.

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Zohr record breaker

In record time for a deepwater gas development of this scale, Eni has announced first production from Zohr. The field was discovered in August 2015 and FID taken in early 2016 - Eni achieved first gas from discovery in 2.5 years.

Zohr is the largest gas discovery ever made offshore Egypt and is located in the Shorouk block. The field has begun production at 350mmcfpd and is expected to grow to 1bcfpd by mid-2018. The speed of development is a testament to Eni's "Dual Exploration Model" which was adopted in 2013. Under this model, Eni works the exploration, appraisal and development planning and phases in parallel while bringing in minority partners at the same time to help fund the costs.

Zohr has >30tcf of GIIP and forms an important piece of the jigsaw to solving Egypt's short gas problem. The new production will help feed the hungry and growing domestic gas demand which Egypt has been trying to manage by raising domestic prices on the one hand and incentivising further gas exploration/development on the other.

The Zohr partners are Eni (60%), Rosneft (30%) and BP (10%). Eni is co-Operator of the project through Petrobel, which is jointly held by Eni and EGPC.

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Kurdistan producers get paid for September

DNO and Genel Energy have reported receipt of USD54 million from the KRG for September crude sales from the Tawke licence - shared by DNO (USD40.7 million) and Genel (USD13.6 million) in line with the interests in the licence.

In addition, a payment of USD10.8 million has been received by Genel and DNO, representing 7.5% of gross Tawke licence revenues during October 2017, as provided for under the receivables settlement agreement.

Separately, the Taq Taq field partners have received a payment of $9.7m from the KRG for September oil sales - Genel's net share of the payment is USD5.3 million.

This is the first set of payments that has been made following Kurdistan’s independence election and the choking back of oil exports from the Kirkuk Area, which has limited the KRG’s cash flows. Although a positive, concerns will continue around the continuity of payments.

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Maersk Drilling exits Egyptian JV in line with strategy

Maersk continues to review and streamline its business portfolio. As part of that strategy, it announced today of its exit of the Egyptian rig company joint venture.

Press release
A.P. Møller - Mærsk A/S ("A.P. Moller - Maersk") and Egyptian General Petroleum Corporation ("EGPC") has today signed an agreement whereby EGPC will acquire A.P. Moller - Maersk’s 50 percent shareholding in Egyptian Drilling Company ("EDC") for USD 100m in an all-cash transaction.

Following the transaction EGPC will become sole owner of EDC and will as part of the agreement take over the entire portfolio, obligations and rights. EDC is one of the leading drilling operators in the Middle East and operates 70 rigs in total of which the vast majority are land based drilling rigs.

The divestment of EDC is in line with Maersk Drilling’s strategy to focus on offshore drilling in the harsh environment and deepwater markets.

“I am very pleased with this agreement with EGPC. The divestment is a natural consequence of our announced long-term plans to exit the EDC joint venture, when the timing was right. EDC has a very strong position in the Middle East, and I am confident that the new ownership will enable EDC to develop its business and capabilities even further,” says Jørn Madsen, CEO of Maersk Drilling.

EDC began operations in 1976 as a 50/50 joint venture between Maersk Drilling and EGPC, which is owned by the Ministry of Petroleum and Mineral Resources in Egypt. EDC employs approximately 5,000 people, whereof 34 are Maersk Drilling employees. Maersk Drilling is currently looking into future job opportunities for its employees in EDC.

Source: https://www.maerskdrilling.com/en/media-center/press-release-archive/2017/12/maersk-exits-egyptian-drilling-company-joint-venture

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CNPC could take over Total's interests in Iran

CNPC is considering taking over Total's stake in a the giant South Pars development if Total needs to exit Iran to comply with any new U.S. sanctions. In October, President Trump refused to certify Iran's compliance with the nuclear deal leading to a Congressional vote on whether to reimpose sanctions on Iran.

The date of the vote has not yet been set , but if sanctions are reimposed they could prohibit companies working in Iran from also operating in the United States. For Total, the stakes are high, where they have much larger operations in the United States.

Total signed the USD1 billion deal to develop the South Pars gas field in July. However, the contract provided mechanisms to allow Total to pull out in the case of sanctions imposition, whereby CNPC has the option to take over Total's stake. CNPC could take over Total's 50.1% interest and become operator of the project if Total is forced to withdraw from Iran. CNPC has a 30% stake, while the Iranian national oil company's subsidiary PetroPars holds the remaining 19.9%. If this goes ahead, then CNPC would shoulder 80.5% of the cost of the project, estimated at $2 billion for the first stage.

Any change would also delay the project as Total is already in discussion with service companies and is expected to award contracts early next year.

The South Pars project will have a production capacity of 2bcf/d plus condensates, Total has said. It would start supplying the Iranian domestic market starting in 2021.

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Aker BP submits three PDOs

Aker BP ASA (Aker BP) has submitted the Plans for Development and Operations ("PDOs") for the Valhall Flank West, Ærfugl (formerly Snadd) and Skogul (formerly Storklakken) fields to the Norwegian Ministry of Petroleum and Energy.


Valhall Flank East
This development represents an extension on the western Flank of the Valhall field. It will be developed from a new Normally Unmanned Installation and will be tied back to the Valhall field centre. The platform will be fully electrified and operated remotely from Valhall. Recoverable reserves are estimated at 60mmboe to be drained using six producers with first oil planned for Q4 2019.

Field partners are AkerBP (35.95%) and Hess Norge (64.05%). Aker is in the process of acquiring Hess Norge and has entered into an agreement to farm-down 10% to Pandion Energy.


Ærfugl (formerly Snadd)
This is a gas condensate field near the AkerBP operated Skarv FPSO. The PDO covers the full-field development and includes the resources in both the Ærfugl and Snadd Outer fields which are planned to be developed in two phases.

The first phase includes three new production wells in the southern part of the field tied into the Skarv FPSO with production planned to commence in late 2020. The second phase continues to be worked up and will target the northern part of the field - it is also planned to be tied into the Skarv FPSO with an estimated startup of 2023. The full field development targets 275mmboe.

Partners in Ærfugl are AkerBP (23.8% operator), Statoil (36.2%), DEA (28.1%) and PGNiG (11.9%).
Partners in Snadd Outer are: AkerBP (30% operator), Statoil (30%), DEA (25%) and PGNiG (15%).


Skogul (formerly Storklakken)
Skogul is located 30km north of Alvheim FPSO, and will be developed as a subsea tieback to Alvheim via Vilje. Recoverable reserves are estimated at 10mmboe. The Skogul production well is the 35th well in the Alvheim area and represents the partners' efforts in extending life and recovery in the area. Production is planned for Q1 2020.

Field partners are AkerBP (65% operator) and PGNiG (35%).

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Kosmos dry well at Lamantin

Lamantin-1 on Block C-12 offshore Mauritaniawas was drilled to a TD of 5,150m and designed to evaluate a previously untested structure. The logs and samples collected suggests the reservoir objective was water bearing with small amounts of hydrocarbons. The well will now be plugged and abandoned.

Kosmos will drill the Requin Tigre prospect next and is targeting 60tcf. The well is epected to take around 60 days.

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In AWE

China Energy Reserve and Chemical Group (“CERCG”) has returned with a second bid for AWE at A$0.73/share, valuing the company at A$463 million. This follows the withdrawal of the earlier offer at A$0.71/share on 4^th December.

On 30^th November, CERCG put out a takeover offer for AWE at A$0.71/share contingent on due diligence, approval by the regulatory authorities and the CERBG board. The offer was at a 30% premium to the share price was deemed insufficient by AWE to grant access for due diligence. The bid was subsequently withdrawn on 4^th December.

CERCG remains fiercely private with limited information in the public domain. It is reported to have deep pockets with material property investments in Hong Kong to the tune of billions. It is also understood that some of the directors are also on the board of China New Energy Mining Limited, which is the JV partner to Sino Gas on upstream gas developments in China.

On 8^th December, CERCG re-launched an offer at A$0.73/share – marginally better but places limited value on the vast contingent resource base of the company with potential upgrade at Waitsia. The approach from CERCG is the third bid in four years. The Lone Star bid at A$0.80/share (A$421 million) in 2016 and Senex scrip/cash bid in 2013 (at A$672 million) were both rejected.

This bid demonstrates continued Chinese interest in pursuing overseas acquisitions, and follows GeoJade’s venture into the international E&P arena with the acquisition of Bankers Petroleum in 2016. However the Chinese state oil companies remain on the sidelines having been burned by poorly timed acquisitions in the past decade, and it is the smaller private Chinese E&Ps and investors that are coming to the foreground.

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Canacol: Sabanas export flowline comes online

Canacol has announced that the Sabanas gas flowline is now connected. It is in the final stage of testing and gas transportation is scheduled to commence on 5^th December. The flowline has a capacity of 40mmcf/d which is expected to be reached in mid-January following completion of a second compression station - initial gas throughout is expected to be 20mmcfd. Gas will be routed from the Jobo processing facility to the Promigas export line at Bremen with the gas to be sold to consumers at Cartagena. Upon reaching the full 40mmcf/d capacity, Canacol's total gas offtake capacity will increase to 130mmcf/d.

Canacol also added that gas sales for October and November averaged 84.1mmcf/d and oil sales (including Ecuador) of 3,025 bbl/d. In December 2018, the company expects gas production capacity to increase to 230mmcf/d following the completion of the second expansion of the Promigas pipeline from Jobo to Cartagena and Barranquilla.

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Breathing new life into Tyra

The Danish Underground Consortium ("DUC") has approved an investment of DKK21 billion (USD3.4 billion) for the full redevelopment of the Tyra field.

DUC members are Total/Mærsk (31.2 %), Shell (36.8 %), Chevron (12 %) and Nordsøfonden (20 %). The development will ensure continued production from Denmark's largest field for years to come and will also rejuvenate important Danish offshore infrastructure. About 80% of the investment will be for modification of existing and construction of new facilities, with the remainder for decommissioning and removal.

The Mærsk press release noted:
"Tyra is the centre of Denmark’s national energy infrastructure, processing 90% of the nation’s gas production.

Through new development projects and third party tie-ins, the redevelopment of Tyra can be a catalyst for extending the life of the Danish North Sea – not just for Maersk Oil and the DUC, but also for Denmark."

"The new infrastructure can enable operators to pursue new gas projects in the northern part of the North Sea, where the most recent development, Tyra Southeast, delivered first gas in 2015 and is producing above expectations."

"The redeveloped Tyra is expected to deliver approximately 60.000 barrels of oil equivalent per day at peak, and it is estimated that the redevelopment can enable the production of more than 200 million barrels of oil equivalent. Approximately 2/3 of the production is expected to be gas and 1/3 to be oil."

The redevelopment has received government approval and will commence in 2019 with the field being shut-in between November 2019 and Summer 2022 for the works to take place.

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Kraken emerges

In mythology, the Kraken was a giant sea monster that dwelled in the present day North Sea. Today, the Kraken field is emerging with production growing day-by-day and a target to reach 50mbopd in H1 2018.

Gross production reached 23mbopd in November (month average) and the second processing train was brought online at the end of the month. The final DC2 production well is now onstream and the DC3 wells are near completion and expected to be brought onstream ahead of schedule. DC4 drilling will commence in 2018 and once online, will bring the field production to 50mbbl/d.
Kraken breathes some new life in the UK North Sea, being one of the small number of sizeable developments in the basin for a number of years. Its start-up has been relatively smooth, with first oil achieved at the end of June 2017 and a steady ramp-up since. Despite some above surface teething issues, these appear largely resolved with the crews getting more familiar with the FPSO operation and continued tuning of equipment.

Source: OGInsights analysis

The field is important for both EnQuest (70.5% operator) and Cairn (29.5%). With the achievement of plateau production, it is expected that one or both partners will farm-down their stake, not least having inherited additional interests from former partner First Oil when it went into administration. The long-life nature of the field, albeit heavy oil, should attract interest from major North Sea players.

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Siccar Point portfolio tidy-up

Siccar Point has an attractive long-term portfolio currently weighted developments. The portfolio includes a number of earlier stage opportunities. In November, the company took the opportunity to prune the portfolio - bringing in a partner on Lyon and selling Jackdaw to a more natural pair of hands.

On 21st November, Siccar Point announced that it had farmed out UK licences P1854 and P1935 to Ineos. The blocks are located in the West of Shetlands and contain the Lyon prospect which is estimated to contain 1-3tcf of recoverable gas. Ineos now has interests in all four fields that make up the Lyon gas cluster: Lyon, Tobermory, Bunnehaven and Cragganmore - this has the potential to be a future gas hub in the area. For Ineos, the transaction builds upon the recent acquisition of the DONG portfolio as it seeks to become a major UK oil & gas player. Post the farm-out, Siccar Point will hold 33.3% in the blocks with Ineos holding 66.6%.

At the beginning of the month, Siccar Point also announced the divestment of its 26% stake in three blocks covering the Jackdaw discovery to Dyas. Jackdaw is operated by Shell (74%) and is a HPHT field. The discovery lies in the J-Block area and is subject to sanction. The project was put on hold by BG in 2014, but continues to hold substantial gas resources that is expected to be monetised in the early 2020s.

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Statoil acquires Martin Linge from Total for USD1.45bn

Total has agreed to sell all of its interests in the Martin Linge field (51%) and Garantiana discovery (40%) on the Norwegian Continental Shelf to Statoil for USD1.45bn with an effective date of January 1st, 2017.Statoil will also receive remaining tax balances with a nominal post-tax value of more than USD 1 billion.

Martin Linge is a long life oil and gas development with estimated recoverable resources in excess of 300 mmboe. Originally scheduled to come onstream in 2017, first production is now expected in 2019 following a series of project delays and cost increases including a tragic accident at the Samsung ship yard in South Korea where the topside is being completed.

Martin Linge is being developed with a manned wellhead platform - the jacket substructure is already installed on location, while the topside is being completed at the Samsung yard in South-Korea and will be transported to Norway early 2018.

Operations will be controlled remotely from an onshore digital operations centre, enabling reduced operational expenditures. Electrification is made possible through a 160 km cable from shore, the longest AC power link in the world. This will reduce CO2 emissions by 200,000 tonnes per year. Following completion of the transaction, Statoil will increase from 19% to a 70% interest in the field.

Arnaud Breuillac, President, Exploration & Production at Total commented "The forthcoming acquisition of the Maersk Oil portfolio, which will make Total the second largest operator in the North Sea, leads us to review our portfolio in this area so as to focus on the assets in which Total will be able to generate synergies and reduce their breakeven points. In this context, given that Martin Linge is Total's only operated asset in Norway, there is limited scope to optimise operations, whereas with Statoil’s leading operating position on the Norwegian Continental Shelf, Statoil is in a better position to optimize this asset for the benefit of all stakeholders. We are therefore satisfied with the agreement with Statoil, a long time trusted partner, which in addition, offers us a satisfactory value for this asset. Norway remains a strategic country for Total as one of the largest contributors to the Group's production and we of course intend to continue bringing our expertise to Norway by focusing in particular on major non-operated assets such as Ekofisk, Snohvit and Johan Sverdrup."

Statoil's EVP for D&P Norway commented "This transaction adds competitive growth assets to our portfolio on the Norwegian continental shelf. The Martin Linge project features innovative solutions to enhance safety, capture value and reduce emissions, in line with our strategy. By leveraging Statoil’s operational experience and existing contracts, we can realise additional opportunities and synergies from these assets."

The transaction involves the transfer of relevant employees from Total to Statoil and remains subject to final due diligence and approval from the relevant authorities. The transaction will increase Statoil's stake in Martin Linge from 19% to 70% with the DFI holding the remaining 30%.

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Eni signs EPSA for Block 52 offshore Oman

The Government of the Sultanate of Oman, Oman Oil Company Exploration and Production ("OOCEP"), a subsidiary of state company Oman Oil Company ("OOC"), and Eni today entered into an Exploration and Production Sharing Agreement ("EPSA") for Block 52, located offshore Oman.

Block 52 is an underexplored area with hydrocarbons potential located offshore in the southern region of Oman. Block 52 has an area of approx. 90,000 Km2, with water depths ranging from 10 to over 3,000 meters. Pursuant to the EPSA, Eni is the Operator of the block, through its subsidiary Eni Oman B.V., with an 85% stake, whilst its partner OOCEP holds the remaining 15% stake.

During the same event, held in Muscat, Eni and Qatar Petroleum signed an agreement for the assignment of 30% interest in Block 52 to Qatar Petroleum. Following the conclusion of such agreement and subject to the consent of the competent authorities of the Sultanate of Oman, the Contractor under the EPSA will consist of affiliates of Eni with a 55% stake, Qatar Petroleum with 30% and OOCEP with 15%.

'The signing of the Block 52 EPSA represents an important milestone in Eni’s strategy to reinforce its presence in the Middle East region. We wish to establish with the Sultanate of Oman, which is a historical Oil & Gas producer in the region, a long-lasting relationship in the best tradition of Eni. It is also remarkable that, the same day, we are welcoming Qatar Petroleum as a partner in Block 52, to join our efforts with such a strong partner that is currently leading the LNG business worldwide', commented Eni CEO, Claudio Descalzi.

Block 52 was awarded to Eni and OOCEP following an international bid round process launched in October 2016.

Source: Eni

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Kurdish operators receive July crude export payments

Kurdish operators have announced receipt of oil sales payments from the KRG today towards July exports:
DNO has confirmed that the Tawke partners have received USD39.5 million
Genel has confirmed that the Taq Taq partners have received and USD10.4 million

These payments are in line with recent payments and should be the last under the "old" system (i.e. before the recent change in terms in exchange for settlement fo historical receivables).

Payment for August sales should be made in November - these should increase with DNO's greater share in Tawke and Genel's elimination of the 30% Capacity Building Payment. However, the recent referendum results casts uncertainty on the way forward between the neighbours in the region and therefore the risk to Kurdistan's financial position and therefore payments has increased.

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Catcher if you can

The Catcher FPSO has arrived on schedule into the North Sea. The vessel is currently at Nigg performing crew changes and resupply ahead of moving to the Catcher field location.

The field remains on track to come onstream by the end of the year. Tweleve wells have been completed ahead of first oil and drilling has been better than expected, encountering 30% more net pay with 40% better well deliverability. As a result, expected plateau production has increased by 20% to 60mboepd. There is potential for a reserves upgrades above the existing 96mmboe 2P. The well results also reduce the total wells required from 20 to 18.

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OPEC may extend yet

Saudi Arabia has been working tirelessly behind the scenes and appears to be gaining good momentum with the major actors of OPEC + 1 (i.e. Russia) for extending the OPEC output agreement beyond April 2018. Saudi Arabia and its new ally, Russia, are keenly in favour of maintaining the cuts until June 2018 and several other producers have recently signaled their support for an extension as well.

Iran: Initially one of the tougher partners at the November 2016 pact discussions given its demand to return to pre-sanction production levels, Iran has played along with the creation of the special cap arrangement. Iranian oil minister, Bijan Zanganeh, has indicated that the country “will cooperate with the majority” on any extension proposal.

Iraq: Has publicly been a vocal critic of the current arrangements arguing that it was not exempt from the cuts (like Libya and Nigeria) as it needed funding to fight the war with Islamic State. Iraqi oil minister, Jabbar al Luiebi, has also been critical of the fact that Iraq has not been allowed to use its own numbers for the calculation of the output cut). Up until now, Iraq has been sending mixed signals about whether it would actually agree to any extension. However the Saudi oil minister, Khalid al-Falih, has been working behind the scenes and made a special visit to Baghdad in May before the OPEC meeting to ensure that Iraq would agree to a 9-month timeframe. Saudi’s diplomatic efforts may have paid off as Iraq is now softening its tone and affirming its commitment to the current agreement; in August 2017, Luiebi stated during a visit to Moscow that it would go along with an extension if one is agreed.

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Senegal moves ahead

Cairn Energy, the operator of the SNE field in Senegal, released a resource update on 22^nd August as part of its half-year announcement.

The updated 2C resource base is 563mmbbl gross (vs. 473mmbbl in May 2016) and now brings it in line with Woodside's estimate of 560mmbbl, but is still far below that of partner FAR which carries 641mmbbl (assessed by RISC). The differing resource estimates is nothing new and we constantly see the other partners playing catch-up with FAR.

Focus is now on FEED with no further drilling planned until after FID. It is envisaged that SNE will undertake a phased development with the initial phase targeting the lower 500 series sands and core area of the upper 400 series sands. The second phase will target the remainder of the 400 series and more outreach parts of the field.

Gross capex is currently estimated at USD2.3 bn, but could come down as the engineering is defined and possibility of Woodside bringing in an existing FPSO. FID for Phase 1 is planned for the end of 2018 with first oil in 2021 and an initial plateau of 75-125mbopd.

The partners are Cairn 40%, Woodside 35%, FAR 15% and Petrosen 10% (Petrosen has the option to increase its interest to 18% during the development phase).

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Sail-away to Catcher

The Catcher FPSO sailed away on 26th August from Singapore. It will take around 45 days to reach the UK North Sea, following which it will be connected and commissioned, a process expected to take 60-65 days with first oil targeting December.

The project is on schedule and c.30% below budget. Development drilling results have been promising with 30% more net pay and 40% better well deliverability. Expected plateau will now increase by 20% to 60mboepd with a potential for reserves upgrade from the 96mboe 2P at sanction.
The Catcher field partners are: Premier 50% operator, Cairn Energy 20%, MOL 20% and Dyas 10%.

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Kosmos London listing at risk as company and advisors face potential legal action

Kosmos' secondary listing is at risk as the Saharawi government had strongly condemned the company's move to list on the LSE. The Sahrawi government has threatened the company's licences in the region as well as legal action against Kosmos and its advisors.

The listing would set a precedent for legal proceedings regarding companies operating in the disputed region which could drag out for years to come. The press release by the Saharwi government is below.

--------------------------------------

Media release – Communiqué

For immediate release


Saharawi government responds to the proposed listing of Kosmos Energy Ltd. on the London Stock Exchange

Bir Lehlu, Western Sahara (August 16, 2017), The government of the Saharawi Republic (the SADR) notes with concern recently expressed plans of the United States-based petroleum company Kosmos Energy Ltd. to trade in securities in a secondary listing on the London Stock Exchange (the LSE).

“Any effort by Kosmos to raise additional capital, including securities offerings and especially on an exchange which is, for the time being, subject to European law results in clear risks for the company and others financially interested in it. Kosmos continues with seabed petroleum exploration in the coastal waters of occupied Western Sahara with an established basis for legal action against the company and its supporting enterprises”, remarked Emhamed Khadad, the SADR official responsible for natural resources following Kosmos Energy’s recent announcement.

Western Sahara, routinely referred to as Africa’s last colony, has been illegally occupied across much of its inland area and part of its coast since 1975. A commitment by the United Nations organization to deliver a self-determination referendum to the Saharawi people who had been the sole, exclusive occupants of the territory, has been stalled as a result of continuing annexation efforts including resources development purportedly done to generate economic benefits for the territory. Four senior level international and national courts have confirmed an occupying Morocco to be without right or title to the territory. “What this means”, noted Khadad, “is that the rule of international law holds that the occupying state is unable to offer exploration licenses and, even less, hold out any rights to petroleum that could be recovered from the seabed.”

In a December 2016 judgment the Court of Justice of the European Union confirmed that Western Sahara is not a part of Morocco and that the kingdom is unable to exercise treaty authority over the territory in respect of trade matters.

A June 2017 judgment of South Africa’s High Court, concerning a shipment of phosphate rock exported seized after export from Western Sahara, concluded that:

“Morocco has no claim to sovereignty over Western Sahara ... Furthermore, it acquired the territory by force [and] we conclude that howsoever Morocco's presence in Western Sahara may be described, it does not exercise sovereignty over the territory".

(A copy of the decision in Saharawi Arab Democratic Republic and Another v Owner and Charterers of the MV 'NM Cherry Blossom' and Others [2017] ZAECPEHC 31 is available online at: <www.saflii.org/za/cases/ZAECPEHC/2017/31.html>.)

The 2017 and 2016 judgments follow one of the United Kingdom High Court in 2015 which confirmed the territorial status of Western Sahara as not being part of Morocco. A securities listing on the LSE, and related activity, faces the risk of precedent in the United Kingdom and by parallel and separate proceedings, in the Court of Justice of the European Union.

“There is no longer any speculation by the SADR government in its safeguarding of the sovereign resource rights of the Saharawi people that formal legal measures will be resorted to in the face of financial activity to capitalize the taking of our resources, and as against activities as such. International law is clear about such matters and we will continue to employ it in the face of a universally derided, illegal occupation”, observed Khadad.

# # #

For additional information and media contact:

Mr. Kamal Fadel
Saharawi Republic representative for Australia and New Zealand
Senior executive of the SADR Petroleum & Mining Authority
T: + 61 2 92 65 82 58

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Kurdistan's outstanding debts to Turkey

A year ago, at the height of the oil price downturn, Kurdistan turned to Turkey for financial aid. At the time, USD1.15 billion was owed to Turkey in the form of loans together with c.USD500 million in outstanding payments to TEC for services provided to the KRG.

The Kurdish Minister of Natural Resources, Dr Ashti Hawrami, proposed to the Turkish Energy Minister, Berat Albayrak, that more funding be provided by Turkey to help Kurdistan with upcoming expenses. The proposal effectively asked Turkey to quadruple its funding to USD4.7 billion (including the existing debts above).

The budgetary position of Kurdistan meant that it was in no position to repay the debts to Turkey in the near term and Dr Ashti’s preferred solution was to transfer the KRG’s equity interests in certain oil assets (Tawke, Taq Taq and Shaikan) to Turkey. Turkey responded saying that if this was the preferred route, it would need further upside given taking a stake in the PSCs would result in the recovery of debts over a longer period than originally envisaged.

As of today, the Turkish debt problem remains unresolved and is an ongoing issue for both the KRG and Turkey. In the context of the upcoming referendum, Turkey is clearly displeased that it is being held but its ability to take strong action against Kurdistan could be detrimental to the recovery of debts. At the same time, Kurdistan could be an important future source of gas for Turkey. For Kurdistan, maintaining amicable relationships with Turkey is key, being the only viable oil export route in the near term. Turkey can make token threats, such as the rumoured closure of a border point, but is unlikely to escalate to anything more serious.

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