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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Canacol on track with Sabanas pipeline

Canacol has signed an agreement for the construction, operation and ownership of the Sabanas flowline. The 82km pipeline will connect the gas processing plant at Jobo to the Promigas trunkline at Bremen.

Source: Canacol June 2017 investor presentation

The USD41 million pipeline will be funded by:

• USD30.5 million from a group of private investors
• USD10.5 million from Canacol

Canacol’s contribution has been almost entirely satisfied by costs incurred to date.
Construction is proceeding on schedule, with first gas transportation expected in December 2017. All rights of way have been acquired, tubulars are on order and civil works are to commence during August 2017.

The Sabanas flowline will provide an additional 40mmcf/d export capacity and will satisfy 40mmcf/d take-or-pay contracts entered into in 2016 with existing and new customers. Canacol will pay a tariff for use of the pipeline in line with other regulated tariffs which will be borne by gas offtakers. Canacol does not have a ship-or-pay commitment for use of the pipeline.

With the additional 40mmcf/d production, Canacol’s production will increase to a 2017 exit rate of 130mmcf/d. The end of 2018 will see another big step change in production with an additional 100mmcf/d coming onstream with the completion of the additional Promigas Jobo-Bremen pipeline.

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Kurdistan referendum: Barzani's legacy

With the Kurdistan referendum fast approaching on 25th September, OGInsights reviews the latest developments in this run-up period. What is important to note is that the question being put to the Kurdistan people is sufficiently vague – the meaning of an “independent” Kurdish state is intentionally not set out. Independence can mean self-rule and independent governance with varying degrees of autonomy from Federal Iraq or complete separation from Baghdad at the extreme.

The referendum should be viewed as an opinion poll, something that reminds the world and reaffirms the Kurdish aspirations for independence. It is not something that will have any immediate impact on the administration of the Kurdistan region, trade between Kurdistan and its neighbours or money flows with Baghdad. It certainly is not a declaration of independence either.

The referendum is symbolic and timing is more opportunistic than reasoned. President Massoud Barzani is coming to the end of his term and holding a referendum as being the first step to eventual independence is his chance to leave a legacy. The turnout is expected to be high and a “yes” vote is deemed inevitable which will score popularity points for President Barzani. Barzani has ensured that the voting ballots, systems and infrastructure is largely in place for a referendum at the beginning of September although the actual date will be the 25th, signalling the seriousness of this referendum for Barzani.

Leaving a legacy seems to be an important driver for this referendum, with Barzani spending much political ammunition to secure it. Turkey was not notified of the date of the referendum lest they would undermine it, Iran will fear reignition of calls by its own Kurds for independence and both the US and Baghdad will be annoyed that the referendum includes the disputed areas after being told to explicitly exclude them.

However, Kurdistan’s neighbours have not reacted to date suggesting a level of tolerance recognising that the referendum could be a tiger with no claws. Any action by neighbours is likely to take place before the referendum as any action taken post the referendum results will likely have minimal meaningful impact on Kurdistan and in some cases could have reciprocal impact on the initiator. For example, whilst Turkey could close the oil export pipeline and halt investment in Kurdistan gas, Turkey does do a lot of other trade with Kurdistan. Similarly, any retaliation by the US could see the loss of Kurdish support for the war in Syria.

The referendum will be closely watched around the world, but the results are not expected to be a surprise.

Related posts:

• Kurdistan independence referendum

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Kurdistan E&Ps have been paid for May shipments

Kurdistan E&Ps have been paid for May shipments.

The Tawke partners have confirmed receipt of USD39.6 million. The amounts will be shared pro-rata by DNO (55%) and Genel (25% WI) and comprises USD33.2 million towards May deliveries and USD6.4 million towards past receivables.

The Taq Taq partners have received USD12.2 million and will be shared pro-rata by Genel (44% WI) and Addax (36% WI). The payment comprises USD11.1 million towards May deliveries and USD1.2 million towards past receivables.

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SNE North is Sirius

Cairn has completed the SNE-1 North exploration well (Sirius prospect), located c.15km north of the original SNE-1 discovery. The well reach TD 2,837m and was completed ahead of schedule. A 24m gross hydrocarbon column was encountered across three intervals with 11m net condensate and gas pay in the primary objective and 4m net oil pay in the secondary objective.

A full set of oil, condensates and gas samples were recovered to surface from the 500 series sands, the same sand series that contributes the bulk of volumes in the main SNE field. The oil is slightly lighter at 35˚ API (vs. 32˚ API in SNE).

Further work will be required to establish the size and commerciality of the discovery, although FAR has assigned 294mmbbl of mean recoverable resources. The find has positive connotations for the block demonstrating further hydrocarbon potential to the north of the block. The well will now be plugged and abandoned and concludes the five well 2017 drilling campaign and the Stena DrillMAX rig will be released.

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Kosmos extends position in Mauritania

Kosmos noted in its Q2 results that it had farmed in to a 15% non-operated interest in Block C-18 Mauritania. The farm-in extends Kosmos' postion in this recently proflific play which contains the Tortue gas discovery to the south.

Tullow Oil holds 90% WI (State 10%) and will reduce its interest to 75% post transaction, whilst retaining operatorship. The block is deepwater (over 2,300m depth) and has recently completed a 600km2 3D seismic campaign.

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Mozambique LNG moves one step closer to FID

On 31^st July, Anadarko finalised two agreements with the Mozambique government (the marine concessions) which pave the way for FID of the LNG project. The agreements would allow Anadarko as operator to progress with the design, building and operation of the marine facilities for the project and could see FID in 2018. The next step is to begin with resettlement plans, the completion of which would allow construction to commence.

Separately, the partners continue with efforts to secure long-term offtake contracts and the high proportion of offtake by equity holders of the licence reduces the risk surrounding the project. Asian players Mitsui (20%) and PTTEP (8.5%) have a need to source long term gas supply, as do the Indian participants ONGC (16%), Oil India (4%) and Bharat (10%). The remaining Area 1 licence holders are Anadarko (26.5%) and ENH (15%).

Area 1 is estimated to hold c.75tcf of recoverable gas and will initially have two LNG trains at the proposed onshore processing plant with 12mtpa capacity for the Golfinho/Atum field. The scale of the resources does pose a threat to upcoming global LNG developments, particularly Australian projects which also target the Asian gas markets, and could see a glut in the 2020s particularly with Qatar also looking to up its LNG exports.

Earlier this month saw Petronas cancel its large Pacific NorthWest LNG project on the west coast of Canada.

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Brasse continues to grow

Faroe has successfully completed the Brasse sidetrack appraisal well 31/7-2A. Very high quality reservoir sands were encountered and the well penetrated an 18m oil and a 4m gas column. Recoverable resource estimates have been increased to 56-92 mmboe (from 43-80 mmboe).

The sidetrack was drilled to a total depth of 2,275m. It is located 1km to the west of the appraisal well (31/7-2) and 2.4km to the south of the main discovery well (31/7-1). The appraisal well will now be plugged and abandoned as planned.

An extensive data acquisition programme was carried out in the 31/7-2A sidetrack, including the cutting of cores together with a full suite of wireline logs and fluid samples. Pressure data also indicates good communication within the reservoir. The data supported an increase in the recoverable resources estimates.

Faroe is now moving the development of the field forward with the aim of fast tracking the development given its robust economics at low commodity prices, which could see first oil in 2020/21.

Extensive feasibility studies have been carried out focussing on a sub-sea development tied-back to one of the hosts in the nearby area (either Brage or Oseberg Sør). This work is ongoing and external studies have already been undertaken for the Subsea Production System (SPS),  flow assurance and pipeline and marine work.  Technical and commercial activities related to the potential hosts were formally initiated in Q4 2016.

The preliminary development plan envisages three to six production wells and an optional water injection well for pressure support.  Initial flow rates from the prolific Brasse reservoir are expected to be higher than previously thought, with predicted delivery rates above 30mboepd. The early estimates of the cost of this development is c.USD550 million mid-case for a scenario consisting of four wells and one subsea template.

Faroe now plans to finalise the concept selection with subsequent submission of a Plan for Development and Operations (PDO) to the authorities in 2018.

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Centrica and Bayerngas combine forces

On 17^th July 2017, Centrica and SWM/Bayerngas announced that they had reached agreement to combine their E&P businesses. The respective E&P businesses will be vended into a newly incorporated JV with Centrica holding 69% and SWM holding the remainder 31% in the JV. Key assets in the combined business include Kvitebjorn, Stratfjord and Ivar Assen in Norway, Cygnus in UK and Hejre in Denmark.

Source: Centrica investor presentation

The combination will create a leading pan-European E&P with Centrica’s assets providing a strong production base and Bayerngas providing a development weighted portfolio. The JV will become one of the largest players across the North Sea and will be the biggest producer in 2017.

European E&P 2017E production rankings
Source: Centrica investor presentation

European E&P reserves rankings
Source: Centrica investor presentation

There is no consideration for the transaction, but Centrica will make a series of deferred payments totalling GBP340 million (on a post-tax basis) into the JV between 2017 and 2022; these payments are in respect of upcoming decommissioning in Centrica’s E&P portfolio.

The move signals Centrica’s and SWM’s desire of moving away from E&P to focus on their core utility businesses, in line with other European utilities in recent years, some of whom have completely exited E&P. This follows on from Centrica’s efforts of streamlining its upstream portfolio with the exit of Canada and Trinidad & Tobago earlier this year and SWM’s search for a buyer of its Bayerngas business.

Centrica was known to be in discussions with ENGIE E&P on a potential combination, however following the latter’s sale to Neptune, Centrica turned its efforts to other partners which likely included other “loose” North Sea portfolios such as Dong (now sold to Ineos) and Maersk Oil as well as consolidator Ineos. Bayerngas has also spent the last couple of years searching for a public E&P merger partner, but a lack of success in finding a suitable candidate eventually led to consideration of Centrica.

The rationale for this deal centers on the positioning of the combined business for an exit. In their standalone forms, the Centrica portfolio was likely to be too large to find a private equity buyer with the two large North Sea vehicles having done their deals (i.e. Chrysaor and Neptune) and with the Bayerngas portfolio having too much development to be attractive.

The combined business is now more balanced and is of a size that one day will appeal to private equity when more money is available in this space. Alternatively, an IPO is another exit option but will have to wait until the equity markets show signs of being open again to the oil & gas sector. Nevertheless the combined portfolio in its current form, whilst sizeable and sustainable for years to come, lacks a growth story needed to entice a buyer, whether that is private equity or the public markets.

The creation of an E&P focussed business through this JV should allow it to pursue a strategy independent of its utility owners, and this includes implementing investment and the portfolio rationalisation necessary to steer the business to an exit in the mid to longer term.

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Turkey-Genel gas update

In 2013, Turkey established Turkish Energy Company (“TEC”) as a vehicle to enter into partnerships with IOCs for dealings in Kurdistan. TEC was a state-backed entity and an offshoot of Turkish Petroleum International Company (“TPIC”).

Earlier this year TEC was placed under BOTAS, the state-owned oil and gas pipelines and trading company, with gas coming back to one of the top items on the agenda of the Turkish government. It is now commanding attention at the highest levels of government, driven by a strong will to secure Kurdish gas to strengthen its hand against Russia.

To this end, TEC and Genel have been in continuing dialogue over the way forward for the Miran and Bina Bawi gas fields, with the talks intensifying in recent months. For Turkey, the interest in the project is strategic and necessary. For Genel, the securing of Turkey as a guaranteed long term offtaker is important in helping in reviving the company’s fortunes following a succession of problems including reserve write downs and production underperformance.This has been compounded by a series of management changes with Tony Hayward and Nat Rothschild leaving the board in June 2017 and the departure of Ben Monaghan on 30 June 2017.

Genel is now craving some stability with focus turning to delivery of the gas project which will take a few years to develop. In the meantime, managing production at Taq Taq remains a near term priority.

Related recent entries:

• Kurdistan independence referendum
• Kurdistan: The Rosneft connection

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Kurdistan independence referendum

At the beginning of June, President Barzani announced that the KRG will hold a referendum for independence from Federal Iraq on 25th September 2017. Given the strong nationalistic sentiment, continued calls for independence for many years and bipartisan support, the referendum is highly likely to have a "yes" outcome.

The KDP, led by ‎Barzani, and is the largest party will use the renewed call to consolidate popular support as it seeks to sideline the other parties. ‎Barzani will also see this as his opportunity to get his name in the history books as he nears the end of his career.

The PUK is also pursuing a long term agenda of independence, but its ‎support for this referendum will be driven by a desire to win back votes after losing seats in September 2013.

Baghdad knows that it will be powerless to block the referendum, and in the lack of a better solution, Abadi will likely look to seek a negotiated outcome when independence talks begin, which will be to the annoyance of his government and rival parties. Iran and Turkey will also fear the resurfacing of this topic as it will ignite renewed calls for independence from its own Kurdish population - for now, this will be partly contained by Turkey having full control over the export of Kurdish crude through the Fishkabour-Ceyhan which runs through Turkey. Kurdistan is also exploring potential export of oil through Iran to diversify its export options, so Iran is an ally for Kurdistan to keep onside for now.

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Brasse flow test shows promising results

Brasse was discovered in June 2016 and following a side-track, recoverable resources were estimated at 43 – 80mmboe. On 3rd July, a little after a year the original discovery was made, Faroe has reported successful flow testing achieving a maximum rate of 6,187mboepd. An upcoming side-track is planned, following which the resource estimates may be updated.

An extensive data acquisition programme was undertaken including a Drill Stem Test, logging, core and fluid sampling. The well showed excellent permeability, similar crude quality to the nearby Brage field (36-37˚ API), no undesirable components and no sand or water.

The results are positive for the future of the field and should help Faroe and its partner (each with 50% WI) in considering the development of the field. Brasse lies c.15km from both the Brage and Oseberg Sør fields and will be developed as a tie-back to one of these. The results could also provide valuable data and validation to support a farm-out which could help accelerate the development.

Source: Faroe June 2016 Investor Presentation

Source: Faroe June 2016 Investor Presentation

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Kurdistan: The Rosneft connection

Rosneft provided a much welcomed source of funding for Kurdistan in February 2017 when it entered into an off-take contract for crude oil. Under the contract, Rosneft will purchase Kurdish crude until 2019 – the volume commitments were not disclosed. In April 2017, Kurdistan received USD1 billion for the first cargo of 600,000 bbl.

The was an important landmark deal for the KRG, being the first time that crude was sold directly to a government-linked oil company. Up until then, all crude was sold to traders. The first cargo was landed at Italy and then transported to Rosneft’s refineries in Germany.

The Rosneft connection was deepened in June at the St. Petersburg International Economic Forum with the signing of a series of agreements supporting the expansion of cooperation between Rosneft and the KRG “in exploration and production of hydrocarbons, commerce and logistics”. The agreements paved the way for the full entry of Rosneft into Kurdistan with the company signing PSCs for five blocks, which were selected from the 22 blocks that the Ministry of Natural Resources put out for licensing at the beginning of the year.

Baghdad has mostly been quiet around Kurdish crude exports and there were no signs of Federal Iraq aggressively pursuing legal cases around the sale of crude by Kurdistan which it viewed as illegal. However, in a surprise turn of events, Baghdad procured a warrant from the Canadian courts to block a Kurdish crude cargo from being offloaded in Nova Scotia on 29th June. The warrant for the arrest of c.722,000 bbl on board the M/T Neverland is a reminder that the dispute between Baghdad and Erbil remains unresolved.

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Point Resources acquires ExxonMobil's Norwegian operated assets

On 29^th March 2017, Point Resources announced its acquisition of ExxonMobil's operated upstream business in Norway for an undisclosed amount (estimated valuation of c.USD1bn). The deal transforms Point Resources into a top 10 producer on the Norwegian Continental shelf and increases production c.10-fold to 48mboepd while adding 128mmboe of oil-weighted reserves. The transaction adds significant technical capability with the transfer of 300 staff to Point Resources.

Point Resources was formed in 2016 by the merger of Core Energy, Spike Exploration and Pure Energy, all portfolio companies of Norwegian E&P private equity specialist HitecVision. The merger created a company with a portfolio weighted towards exploration and development positions (e.g. Brage, Brasse, Pil) and the acquisition of the ExxonMobil assets helps to reweight the portfolio into more of a full cycle one.

The key assets acquired were ExxonMobil’s operated positions: Balder, Ringhorne and Jotun; Forseti is being decommissioned. Point Resources has identified significant upside in the asset base that can be achieved through infill drilling – likely to have been overlooked by ExxonMobil with the portfolio being increasingly immaterial within ExxonMobil’s global business. For ExxonMobil, the divestment leaves it with a non-operated portfolio in Norway and therefore a much lower country cost base, but still provides a platform to access high impact Norwegian and Barents Sea exploration.

Source: Wood Mackenzie
4D seismic has identified new development locations and exploration targets around Balder and Ringhorne

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Gina Krog nears first oil

The NPD has today granted Statoil, the operator, to commence production at Gina Krog in June. The field was originally a gas discovery made in 1974 and had been considered for development on a number of occasions throughout history. In 2007, oil (and gas) was discovered in a nearby prospect and Gina Krog was subsequently reviewed again with a full appraisal and delineation programme taking place between 2008-2011 which confirmed substantial amounts of oil under the entire structure.

A Plan for Development and Operation was submitted in December 2012, with approval obtained in March 2013. The field will be developed using a fixed steel platform and FSO, with oil exported via shuttle tankers. The development is planned to utilise 10 production wells and 4 gas combined injection/production wells. The field is estimated to contain 225mmboe. Most of the gas will initially be re-injected for reservoir support with minimal sales gas during this first phase. This will be followed by a gas blow-down phase, expected to commence in the mid-2020s which will see gas exported to the Sleipner facilities for processing and onward sale.

The partners in the field are:

• Statoil 58.7%, operator
• KUFPEC 15%
• Total 15%
• PGNiG 8%
• Aker BP 3.3%

Total has been offloading its stake in Gina Krog since 2014 in an attempt to reduce exposure to relatively high cost fields and development capex.

• In 2014, it sold a 8% interest to PGNiG along with a package of other Norwegian assets
• In 2015, Total had agreed to sell a 15% interest to Sequa Petroleum – the latter pulled out of the deal in April 2016 citing market conditions
• In January 2016, KUFPEC acquired a 15% interest as part of a wider package of Norwegian assets from Total
• Total current retains a 15% stake and it is rumoured that this will be sold to OKEA for USD350 million

Total is aiming to move down the cost curve by divesting higher cost assets globally. Its near-term capex is 20% weighted to Norway post Gina Krog start-up, so any sale proceeds will be a welcome contribution to ongoing spend, including the Total operated Martin Linge development which is scheduled to produce first oil in early 2018.

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Kraken on track for first oil in June

EnQuest has reported that Kraken remains on track for first oil before the end of June 2017. Drilling is now complete at the first two drilling centres (DC1 and DC2), the rig is currently at DC3. Drilling performance to date has de-risked delivery of the project to and beyond first oil.  At start up, 7 producers and 6 injectors will be in place. Handover of FPSO systems from commissioning to operations continues and the wells will be brought onstream in a phased manner in June. EnQuest emphasises that the project continues to be under budget and on schedule.

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INEOS acquires DONG E&P portfolio

On 24^th May, INEOS announced the acquisition of DONG's E&P business for USD1.05bn with two further contingent payments:

• USD150 million relating to the Frederica stabilisation plant; and
• USD100 million subject to the development of Rosebank

As part of the transaction, DONG will retain all hedges that are currently in place (worth USD285 million) and cashflows from the oil & gas business (worth c.USD310 million). Ineos will adopt all decommissioning liabilities (c.USD1.1 billion).

The deal includes a portfolio of long life assets with 100mboepd production and 570mmboe of commercial reserves and contingent resources. The portfolio's corner stone assets are Ormen Lange (Norwegian gas) and Laggan-Tormore (new gas field in West of Shetlands).

All 440 DONG personnel will transfer to INEOS on completion, which is expected towards the end of 2017. The deal with propel INEOS into the top 10 league of North Sea players and enable the company to significantly expand its trading and shipping activities.

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Private equity backed Neptune Energy acquires Engie E&P

On 11^th May, Neptune Energy announced that it had agreed to acquire Engie's upstream portfolio, Engie E&P International ("EPI"). In 2011, Engie had sold 30% of EPI to China Investment Corporation ("CIC"), retaining a 70% interest in the business. As part of the transaction, Neptune Energy will pay USD3.9 billion for the 70% stake and also take over CIC's 30% stake, in return for CIC becoming a 49% shareholder in Neptune Energy. The Carlyle Group and CVC Capital Partners will together hold 51% in Neptune Energy.

The USD3.9 billion headline transaction value includes c.USD95 million of contingent payments linked to certain operational milestones. EPI will also retain the decommissioning liabilities associated with the portfolio (i.e. transferred to Neptune Energy), allowing Engie to deconsolidate c.USD1.2 billion of decommissioning liabilities from its balance sheet. The deal implies a transaction multiple of EV/2P of USD6.3/boe (based on transaction value of USD3.9 billion).

The EPI portfolio is focussed on North West Europe with additional operations in North Africa and South East Asia and includes a mix of exploration, development and production assets. However, Engie has agreed to retain the Algerian gas development as part of the deal. The portfolio will be gas weighted and is underpinned by a number of key long-term assets including Snøhvit and Njord in Norway, Cygnus in the UK, Römerberg in Germany and Jangkrik in Indonesia.

The acquisition will propel Neptune Energy into one of the largest international E&Ps with the deal expected to close at the beginning of 2018.

International E&P reserve rankings
Source: Company disclosure, OGInsights

International E&P 2016 production rankings
Source: Company disclosure, OGInsights

Neptune was established in 2015 by The Carlyle Group and CVC Capital Partners, targeting large oil & gas opportunities becoming available during the oil price downturn It is headed by industry veteran and former Centrica CEO Sam Laidlaw. Neptune intends to grow the portfolio organically and through bolt-on acquisitions, with ambitions to create a “large, independent E&P company” over the next five years.

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