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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