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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Yakaar - major gas discovery offshore Senegal

 Kosmos has made a substantial 15tcf gas discovery offshore Senegal. The Yakaar-1 well on the Cayar Offshore Profond licence intersected a gross hydrocarbon column of 120m and encountered 45m of net pay. The well confirmed the presence of thick, stacked, reservoir sands over a large area with very good porosity and permeability.

This discovery marks the continuation of Kosmos’ success in the Mauritania/Senegal river basin (Tortue, Ahmeyin, Marsouin and Teranga). Yakaar and Teranga together hold 20tcf (Pmean gas resource) and creates the opportunity for a second LNG hub in Senegal (in addition to the planned Greater Tortue Area).

Source: Kosmos Energy May 2017 company presentation

Kosmos has revised its exploration schedule since February 2017, introducing Hippocampe to the mix which has been prioritised ahead of Lamantin and Requin Tigre. Hippocampe is potentially a more valuable, liquid prone prospect and would likely be easier to commercialise in the case of success than the deepwater gas resources to date.

The drilling schedule over the next 12 months is now:

• Tortue-DST (imminent)
• Hippocampe-1 (Q3/4 2017)
• Lamantin-1 (Q4 2017)
• Requin Tigre-1 (Q4 2017/Q1 2018)

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DNO: Branching out

 

In a move as surprising as TransGlobe's entry into Canada, DNO has announced the acquisition or Origo Exploration, a UK and Norway focussed private explorer backed by GNRI, Riverstone and Temasek. As consideration, DNO will assume Origo's exploration commitments and licence obligations.

Origo has interests in 11 blocks offshore UK and Norway, with 20-30% non-operated interest in each block. This portfolio is expected to generate around three exploration drilling opportunties per year. The management team and staff will be reataiend as part of the acquisition as will its office in Stavanger.

DNO could use this platform to establish a North Sea base (organically and through acquisitions), and although the strategic logic of this acquisition is currently unclear, it presents a new region for DNO to replicate its past exploration and operational success. It also signals the fact that DNO may see limited attractive opportunities in Kurdistan to reinvest its growing cash base on a risk-reward basis.

Origo Portfolio
Source: Company information, NPD

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Major interest in Senegal

On 3rd May, Total announced that it had signed two agreements with Senegal:

• Acquisition of the RPO block (Total 90%, Petrosen 10%) which lies in deepwater immediately adjacent to the SNE and FAN discoveries (Cairn 40%, Woodside 35%, FAR 15%, Petrosen 10%)
• Agreement to perform studies to assess the exploration potential of Senegal’s ultra-deep offshore and become operator of an exploration block.

This activity follows the recent transaction by BP into Kosmos’ exploration and appraisal acreage in Mauritania and Senegal, and CNOOC Nexen’s strategic partnership with FAR in Senegal and The Gambia. In the latter, the partnership covers an initial two year period, providing for co-operation and potential joint bidding on farm-ins, acquisitions and open acreage. FAR and CNOOC Nexen will also share technical expertise and relationships.

While the tangible benefits of this relationship cannot currently be quantified, CNOOC Nexen will be a useful partner to have as SNE progresses towards FEED and may eventually acquire or help fund FAR post FID. CNOOC Nexen could also have an interest in FAR’s Gambian blocks that lie to the south of SNE.

CNOOC is an established player in Africa with development/production in Uganda and Nigeria and exploration interests in Equatorial Guinea, Gabon and the Republic of Congo.

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Saudi Arabia: Consolidating power and austerity tested

Earlier this week, Saudi Arabia announced two pieces of news that the oil markets will be keeping a close eye on. In this latest episode of palace intrigue, King Salman has taken further steps to consolidate power in the Salman branch of the royal family and reversed some of the austerity measures implemented in 2016, the latter signalling tears in the fabric of the social contract with the Saudi public.

King Salman’s sons, Abdulaziz bin Salman and Khaled bin Salman, will become Minister of State for Energy and Saudi Ambassador to the US respectively.

• Prince Abdulaziz has held a variety of senior positions in the oil ministry through the years and was a proponent of abandoning the market share strategy
• Prince Khaled has served as an advisor to the Saudi embassy in Washington – his placement will be to help strengthen ties between the US and Saudi, consistent with the messages since the Trump and Deputy Crown Prince meeting in March 2017

Prince Abdulaziz and Prince Khaled are half-brothers; Prince Khaled is a younger brother to the Deputy Crown Prince, Mohammed bin Salman.

The other key decision this week was the reversal of civil service salary and benefits cuts. The austerity measures have caused discontent with the public, of which c.70% work for the civil service, leading to cries demanding the reversal of salary cuts, reinstatement of benefits, scrapping the planned IPO of Saudi Aramco and a change of the ruling system from an absolute to a constitutional monarchy – the latter being a key concern and threat to the Salmans’ power. The reversal of the cuts were well received and although undermines the economic outlook of Saudi Arabia, is clearly much more desirable than public revolt.

The temporary austerity measures reduced the spending deficit from USD97 billion in 2015 to USD79 billion in 2016. The target for 2017 was set at an ambitious USD53 billion, but this now looks unachievable with the announced reversals. The reversals place the Deputy Crown Prince in an awkward position within the family’s diverging aspirations for the Kingdom with the potential undermining of his Vision 2030 which aimed to scale back the public sector wage bill and civil service, with diversification of the economy. The durability and longevity of other Saudi measures and now being put to the test.

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More innovative investment from Schlumberger for Sound Energy

Sound and Schlumberger have agreed to extend their partnership under the existing Field Management Agreement. In an era where more innovative financing arrangements are being seen, Schlumberger will be granted 27.5% interest in the Meridja and Tendrara Relinquished Areas in exchange for providing services.

Schlumberger will carry out the upcoming geophysical programme which will include:

• 2,600km of new 2D seismic covering the Paleozoic across the Tendrara and Meridja areas; and
• 24,000km² of gravity gradiometry

The programme has an estimated value of USD27.2 million and will be completed over the next 12 months in stages, with an updated prospect inventory produced at each stage.

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Premier sells out of Pakistan

Premier has announced the disposal of its Pakistan business for USD65.6 million to Al-Haj General Trading Co. The sale process for these assets was initiated in 2015 after an unsolicited approach and culminates with today's announcement.The Pakistan assets comprise six non-operated producing gas fields which produced c.47mmcfpd and generated c.USD41 million in 2016.

Premier has been present in Pakistan since 1988 and in 1990, made the Qadirpur discovery. Since then, the company has acquired interests in five other fields, all located onshore. The fields are long-life assets with low operating costs. All production is sold to the government-owned gas utilities, SSGCL and SNGPL.

This disposal is in line with Premier's strategy to dispose of non-core assets to reduce net debt. The deal is expected to close at the end of the year and is pending government and regulatory approvals. The effective date of the transaction is 1st January 2017.

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FAR AMI with CNOOC in Senegal and The Gambia

On 31^st March, FAR announced that it had entered into an Area of Mutual Interest Agreement with Chinese state giant CNOOC for the joint co-operation on the evaluation of and entry into new opportunities across Senegal and The Gambia.

This follows on FAR’s farm-in to 80% of Blocks A2 and A5 in Gambia from Erin Energy earlier this week.

The announcement on the arrangement with CNOOC follows:

“FAR has signed an Area of Mutual Interest (“AMI”) agreement with CNOOC UK Limited (“CNOOC UK”). The AMI covers selected licences offshore Senegal and The Gambia within the designated area.

The AMI provides FAR and CNOOC UK with agreed arrangements to partner in evaluating, bidding, negotiating and managing joint ventures on farm-in and open acreage opportunities for oil and gas licences. The AMI agreement period is for two years.

In combination, FAR and CNOOC UK bring together expertise of the Mauritania-Senegal-Guinea-Bissau (“MSGB”) offshore basin and the capabilities of an international deep water operator.
FAR and CNOOC UK are committed to building long term strategic relationships with the host Governments of Senegal and The Gambia and their people.
This agreement positions FAR to further expand its portfolio and establish itself as one of the major players in the rapidly emerging MSGB Basin – a basin that is increasingly attracting the attention of the world’s oil “majors”.

CNOOC UK Limited is a subsidiary of CNOOC Limited which (together with its subsidiaries) is the largest producer of offshore crude oil and natural gas in China and one of the largest independent oil and gas exploration and production companies in the world.”

Related Links

• FAR signs strategic AMI Agreement with CNOOC UK Limited 
• FAR expands exploration portfolio in West African hot spot – Secures 80% stake in high potential offshore blocks in The Gambia 

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Shell sells onshore Gabon to Carlyle

On 24^th March, Shell announced the sale of its onshore Gabon assets to Assala Energy Holdings (a portfolio company backed by Carlyle Group).

Assala will pay USD587 million and assume debt of USD285 million, taking “enterprise value” to c.USD870 million. Shell will also receive up to a further USD150 million in contingent payments depending on oil prices and performance. This compares with a Wood Mackenzie NPV10 of c.USD600 million and implies that some value being placed on the gas resources.

The onshore portfolio comprises c.60mmbbl of oil (commercial) and c.160bcf of contingent gas. The gas is currently undeveloped due to a limited market, but could one day be used to supply local power generation. The portfolio produces c.35mbopd of and Shell Trading will retain lifting rights from the assets for the next five years.

The licences being acquired are a mix of PSCs and concessions with some of the concessions being converted into PSCs over the last 10-20 years when they came up for renewal. The licences are owned directly and indirectly through a JV with the Gabonese government (75% Shell, 25% State). The largest asset in the portfolio is Toucan which commenced production in 2003 – significant investment was made between 2012-2014 as part of an additional phase of development to extend the field life to c.2030.

The offshore licences (BC9 and BC10) are excluded from the same, where Shell made the large Leopard-1 discovery in 2014 which is estimated to contain close to 1tcf of recoverable gas.

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Bowleven Bomono farm-out

Bowleven and Victoria Oil & Gas ("VOG") have signed a farm-out agreement relating to the Bomono production sharing contract. VOG is a domestic Cameroon gas supplier, and gas upcoming production from Bomono fits in with its strategy of expanding local supply.

Bowleven will retain a 20% operated interest in the Bomono PSC and VOG will have an 80% interest. Bowleven will receive £100,000 worth of new ordinary shares in VOG and a 3.5% royalty from VOG’s production share from the licence, with a cap limiting the total royalty payments to USD20 million. VOG will complete the civil engineering (c.USD6 million) and Bowleven has agreed to pay 50% of any deficit, limited to a USD2 million.

Gas produced from the Bomono PSC is expected to be fed into the customer distribution network owned and operated by Gaz du Cameroun, a wholly owned subsidiary of VOG and the gas will be sold to GDC less a tolling fee. First gas supply to the GDC network is anticipated to start following granting of a Provisional Exploitation Authorisation ("PEA") and other approvals.

Bowleven’s detailed prospect inventory indicates there is 146bcf and 263bcf of mean un-risked GIIP in the Tertiary and deeper Cretaceous reservoir intervals respectively. Completion of the deal is subject to the grant of a PEA over the Bomono PSC and approval from the Cameroon Government.

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Perenco acquires Gabonese assets from Total

On 27^th February Total announced that it had agreed the sale of its Gabonese assets to Perenco for USD350 million. Perenco will acquire:

• Total Participations Petrolières Gabon ("TPPG") a wholly owned subsidiary of Total which has interests in 10 assets; and
• 5 assets from Total Gabon, the publicly listed entity in which Total owns 58.3% and the government of Gabon 41.7%

The package will comprise of 12 fields (some are owned by ‎TPPG and Total Gabon) with 13mbopd production as well as the operated Rabi-Coucal-Cap pipeline. Perenco will acquire operatorship of all the assets apart from Rabi which is operated by Shell.

The assets are mature with the majority currently having an expected end of life between 2020 and 2030. However the deal fits with Perenco's successful strategy of creating value from mature assets. Perenco has a track record of exploiting mature assets around the world, including in Colombia, the UK, Congo and Cameroon. Perenco already has assets in Gabon and this acquisition provides an opportunity for operational and cost synergies and cements West Africa as a core region for the company.

Although the assets provide only oil production, there ‎are significant contingent gas resources especially in Rabin with an estimated 250 bcf gas cap. Perenco is currently the sole gas producer in the country, supplying local power plants and the new gas provides significant back up volumes.

For Total, the divestment will contribute towards the 2014 mandated divestment target of USD10 billion to 2017, of which c.USD8 billion has been achieved to date. It should be noted that this does not represent a complete country exit for Total which still retains assets through Total Gabon, such as Grand Anguille and the deep water Diaba exploration block.

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Sterling sells out to Oranje-Nassau Energie

Sterling Resources has announced it has entered into an agreement to sell its SRUK Holdings subsidiary to Oranje-Nassau Energie for a net consideration of USD113 million, assuming the bonds are fully redeemed and the super senior revolving credit facility is cancelled. Sterling anticipates a completion date of 15th May.

Following Sterling’s recapitalization in May 2016, the board of continued to review and pursue various M&A opportunities to rebuild the business. Sterling considered a number of opportunities and alternatives, including mergers with a variety of potential counterparties. Ultimately, this process culminated with the board of Sterling recommending the sale of SRUK Holdings to Oranje-Nassau. Once the transaction is approved by shareholders, Sterling will no longer have

any business operations and it currently intends to undertake a voluntary winding-up, with the distribution of all net proceeds of the transaction to shareholders. The shares of Sterling are expected to cease trading and be delisted from the TSX-V following the final distribution.

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More success at Jacana

GeoPark today announced the successful drilling and testing of the Jacana-11 appraisal well on block LLA-34. The well, located 2.5km southwest of Jacana-6 and extends the Tigana/Jacana oilfield to the south-west edge of the block. The well reached TD of 11,618ft and did not encounter the oil-water contact.

Jacana-11 tested at c.2,100b/d (18.7 API, <1% water cut) with an ESP from the Guadalupe formation, and the well is already in production.

The Jacana Sur-2 well is the next well scheduled to be drilled and is targeting a further extension of the field in the northwest direction.

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BP continues foray into clean energy and US gas supply

BP has agreed to acquire Clean Energy Fuels Corp's biomethane production assets for USD155 million, expanding BP's gas supply portfolio in the US. BP will take over Clean Energy Fuels Corp's existing and two new biomethane production sites as well as supply contracts from third parties. As part of the deal, the Clean Energy will also signed a long-term agreement to purchase biomethane from BP.

Press release:

CHICAGO, Ill. and NEWPORT BEACH, Calif. – BP p.l.c. (NYSE: BP) and Clean Energy Fuels Corp. (Nasdaq: CLNE) today announced that BP will acquire the upstream portion of Clean Energy’s renewable natural gas business and sign a long-term supply contract with Clean Energy to support the firm’s continuing downstream renewable natural gas business. The deal enables both companies to accelerate the growth in renewable natural gas supply and meet the growing demand of the natural gas vehicle fuel market.

Renewable natural gas fuel, or biomethane, is produced entirely from organic waste.  As a fuel for natural gas vehicle fleets, including heavy-duty trucks, it is estimated to result in 70 percent lower greenhouse gas emissions than from equivalent gasoline or diesel fueled vehicles.

Under terms of the agreement, BP will pay $155 million for Clean Energy’s existing biomethane production facilities, its share of two new facilities and its existing third party supply contracts for renewable natural gas. Closing the transaction is subject to regulatory approval. Clean Energy will continue to have access to a secure and expanding supply to sell to the growing customer base of its Redeem™-branded renewable natural gas fuel through a long-term supply contract with BP.

“Demand for renewable natural gas is growing quickly and BP is pleased to expand our supply capability in this area,” said Alan Haywood, chief executive officer of BP’s supply and trading business. “BP is committed to supporting developments towards a lower carbon future and, working with Clean Energy, we believe we will be well-positioned to participate in the growth of this lower carbon fuel in the U.S.”

Clean Energy, in turn, will be able to expand its Redeem customer base at its North American network of natural gas fueling stations, allowing customers to take advantage of the ease and affordability of switching to a fuel that is both renewable and can significantly reduce greenhouse gas emissions compared with diesel.

“We started our Redeem fueling business from scratch less than four years ago and have grown it into a significant enterprise,” said Andrew Littlefair, Clean Energy’s president and chief executive officer. “This transaction will help to take it to the next level. BP’s investment in and focus on renewable natural gas supply will ensure that Clean Energy can meet the growing demand of our customers for low carbon, renewable fuel.”

Clean Energy will buy renewable natural gas fuel from BP and collect royalties on gas purchased from BP and sold as Redeem at it stations. This royalty payment is in addition to any payment under BP’s contractual obligation.

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Africa Oil - slowly progressing

Africa Oil published its 2016 financials last night - the USD850 million company (market capitalisation) ended the year with cash-in-hand of USD463 million.

The release included few updates – G&A was down c.50% year-on-year as a result of lower equity-based payments and the impact of the weak Canadian dollar on head office salaries, and the company reported a small USD6.5 million write off on its Ethiopian assets.

Attention remains focused on the Lokichar Basin development - preparations for FEED are underway, the pipeline Joint Development Agreement is currently in the final stages of negotiation. Separately the conclusion of the Maersk carry, an additional USD75 million of development carry may become available to Africa Oil upon confirmation of existing resources.

During Q4 2016, the company elected to relinquish its 15% working interest in the South Omo Block in Ethiopia, resulting in the USD6.5 million impairment charge mentioned above. Africa Oil’s joint venture partners in the Rift Basin Area of Ethiopia and Block 9 in Kenya have provided notification of their intent to withdraw from the joint venture; the company’s working interest in the blocks will therefore increase to 100%. These licences are due to expire in February and June 2017, respectively.

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Kosmos exploration - 2017 rising stars

With a strong balance sheet, cash flow generation in Ghana and exploration/development carry provided by BP through the recent Mauritania and Senegal deal, Kosmos is well positioned to
focus on its 2017+ exploration drilling plans, which will "test some of the largest prospects identified by the industry".

Despite its current gassy position in West Africa, management emphasises its confidence in finding higher value liquids: "Updated hydrocarbon charge model explains results to date and predicts phase - we believe there is a strong chance of finding oil or liquid-rich gas on the outboard basin floor fan fairways".

The high-graded 2017 prospect portfolio comprises:

Yakaar Prospect (Senegal): 15tcfe + 0.75-1.5bnbbl (gross unrisked) prospect located down-dip of the Teranga-1 gas discovery – combination structural-stratigraphic trap, well-defined on 3D with AVO support

Requin Prospect (Mauritania): 5–10tcfe + 0.25-1.1bnbbl (gross unrisked) prospect located outboard of the Tortue gas discovery – combination structural-stratigraphic trap, defined on 2D, 3D seismic currently being processed

Lamantin Prospect (Mauritania): 2-3bnboe (gross unrisked) prospect located in the north of the region – combination structural-stratigraphic trap with flat spot, defined on 2D, 3D interpretation currently in progress.

Requin Tigre Prospect (Senegal): 60tcfe + 3-6bnbbl (gross unrisked) resource potential located outboard of the Tortue gas discovery – combination structural-stratigraphic trap, defined on 3D seismic with AVO support and flat spot, awaiting final volumes to complete prospect evaluation and confirm well location

In terms of upcoming funding, the insurance payments should continue to cover the ongoing costs associated with the Jubilee repair. Continued TEN development drilling in 2018+ should help boost production and cash flow from Ghana. In addition the Atwood Achiever drilling contract expires in November this year and partner BP is set to provide in excess of USD900 million of cash and carry.

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Premier refinancing terms agreed

Following an extensive negotiation process, the terms around the refinancing of Premier Oil’s debt have been agreed. This will be followed by “lock-ups” with lenders in February and final implementation by the end of May.

On 3rd February, Premier Oil announced that it had agreed with key members of the “Private Lending” group on the refinancing terms. The terms include:

• Retaining the existing USD3.9 billion facilities with maturity extended to May 2021
• Covenants relaxed to 7.5x in 2017, 5x by end 2018 and returning to 3x by 2019
• Covenant net debt (including Letter-of-Credit) to be less than USD2.95 billion by end 2018

This terms will now be circulated to credit committees for approval, including RCF, term loan, Schuldschein and private placement noteholders), with lock-up agreements expected by the end of the month. The amended terms will also be presented to the public bondholders, with negotiations with convertible bondholders also close to a conclusion.

As a way to reduce increased interest payments under the new terms, Premier Oil will issue equity warrants for up to 90 million new shares (15% of issued shares) at 42.75p/share. This could be worth around USD50 million, although there is an option for lenders to take up synthetic warrants as a deferred fee of comparable value, reducing warrants issued.

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Equalising the buyer and seller: Shell and Chrysaor's oil price contingent payment structure

After a tumultuous period of oil prices with investment decisions and M&A transactions put on hold, the outlook is beginning to stabilise in 2017. With more comfort on the near term trajectory of oil prices, the corporate mind-set is shifting from balance sheet management to strategic re-focussing and growth.

Nevertheless, buyer-seller price expectation gaps still remain and a way to bridge this gap is the use of oil price contingent payments in a transaction. The last time this mechanism was seen in a major market deal was Seplat’s acquisition of Chevron’s assets in Nigeria in 2015. Today, this novel structure was seen again in Chrysaor’s acquisition of Shell’s North Sea portfolio, with an additional twist.

In the Chrysaor acquisition, the terms were as follows - Chrysaor would make payments to Shell of up to USD600 million split over the 2018-2021 period:

• First payment to be made if Brent rises above USD60/bbl in 2018 and 2019
• Second payment to be made if brent rises above USD70/bbl in 2020 and 2021
• Full payout of the USD600 million is made if Brent reaches USD95/bbl anytime in the 2018-2021 period

However, Chrysaor also managed to secure downside protection on its acquisition should oil prices fall. The transaction allows for Shell to make a payment to Chrysaor of up to USD25 million a year (totaling USD100 million) between 2018-21 should Brent fall in the range of USD47.5–52.5/bbl. Full payout of the USD25 million is made in each year if Brent falls below USD47.5/bbl.

The above structure strikes a balance in providing Shell protection from selling the assets too cheaply in a rising oil price environment and Chrysaor overpaying should oil prices fall. Given the structure of the mechanism, it is clear that the contingent consideration is based on near term rather than long term oil price performance with the size of the payments reflecting the impact on near term production cash flows depending on the direction of the oil price. The long stop date of 2021 is relatively long for an M&A transaction, but suitable for a transaction of this nature where oil prices behavior is exhibited over a longer period of time. While longer periods in which contingent payments are active are normally more beneficial to the seller, the mirroring contingent payment from Shell to Chrysaor in this instance puts both the buyer and seller on equal footing.

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Chrysaor future: Acquisition of Shell North Sea portfolio

On 31st January, Chrysaor announced that it had agreed to acquire a portfolio of North Sea assets from Shell for USD3 billion. The transaction is expected to close in H2 2017 and will transform Chrysaor into one of the largest North Sea focussed E&P companies, who will adopt 400 staff from Shell as part of the deal.

The full-cycle portfolio, which comprises exploration, near-term development and production, produced 115mboepd in 2016 and 350mmboe of 2P reserves. Chrysaor has already identified a number of growth opportunities in the portfolio including incremental recovery to extend field life and intends to implement a programme of near field drilling around key hubs.

The acquisition will be funded by:

• USD1.5 billion bank debt
• USD1 billion investment from Harbour Energy
• USD0.5 billion from existing company and shareholder funds and a financing package provided by Shell

An important component of the deal is that Shell will retain a decommissioning liability of USD1 billion, in a which mirrors EnQuest’s recent acquisition of BP’s North Sea assets. The decommissioning costs associated with the portfolio are currently expected at USD2.9 billion (2016 real terms) and USD3.9 billion in nominal terms. There are no material decommissioning costs in the near term, however, Chrysaor has provided security for its exposure to the liability through letters of credit from part of its bank credit lines (on top of the USD1.5 billion bank debt). (Further discussion in our Siccar Point article).

Harbour Energy is a private equity vehicle backed by EIG Global Energy Partners and led by Linda Cook as CEO. Ms Cook was previously at Shell for 29 years where she was in charge of Shell’s gas and renewables business. She left in 2014 after losing out to Peter Voser for the spot of Chief Executive of Shell. She will now act as Chairwoman of Chrysaor.

The transaction also allows for USD780 million in contingent payments, comprising USD180 million for future exploration success and USD600 million for higher oil prices.

The list of assets acquired are as follows:

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What E&Ps do best: EnQuest acquires North Sea assets from BP for USD85 million

EnQuest has agreed to acquire a package of assets from BP, which includes a 25% operated interest in the Magnus field and various infrastructure interests, adding 15.9mmboe of 2P reserves and 4.2mboepd or production. EnQuest will consolidate its infrastructure interests by acquiring 3% in the Sullom Voe Terminal (currently hold 3%), 9% of the Northern Leg Gas Pipeline (currently hold 5.9%) and 3.8% of the Ninian Pipeline System (currently hold 2.7%).

The transaction makes use of an innovative financing structure in which EnQuest will not have to front any cash for the acquisition. The USD85 million consideration will be funded by deferred consideration payable from the production cash flow of the assets acquired. BP will retain the decommissioning liability in respect of the existing wells and infrastructure on the assets acquired – in exchange, EnQuest will pay 7.5% of BP’s decommissioning cost on the working interest on a post-tax basis.

As part of the deal, EnQuest also has the option to receive USD50 million from BP for undertaking the management of the decommissioning on the Thistle and Deveron fields. EnQuest currently owns 99% of these fields, with BP owning the remaining 1%. BP (and ConocoPhillips) currently retain the decommissioning liability on these fields due to a series of historical transactions, but EnQuest has the opportunity to benefit if it can manage the decommissioning more efficiently and effectively.

EnQuest has the opportunity to upsize in the assets with an option to acquire the remaining 75% of Magnus (from BP) and BP's interest in the associated infrastructure for USD300 million (subject to working capital and other adjsutments). The option is exercisable between 1 July 2018 and 15 January 2019, with EnQuest’s upfront payment limited to USD100 million and the remainder funded by a vendor loan from BP.

This transaction is aligned with EnQuest's reputation for creating value from late life assets with remaining resource potential. Magnus forms part of EnQuest’s hub around the Sullom Voe Terminal and EnQuest has the ability to maximise the potential of the field given its experience in the area and without the overheads of a majors. The relatively late life and small size of Magnus in BP’s global portfolio would have meant it received less attention and ability to obtain capital for investment would have been constrained. EnQuest has already identified synergies on Magnus with its existing assets and opportunities to operate the asset more efficiently.

Magnus overview
Source: EnQuest acquisition presentation

Magnus operational bench-marking
Source: EnQuest acquisition presentation

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Taq Taq Tumble

At the end of October, we raised the prospect of a potential downgrade at Taq Taq following a disappointing production update from Genel.

On 24^th January, Genel provided updated guidance of 24-31mbopd production average for the field in 2017, down from 60.2mbopd in 2016. The declining production from the field has already been well publicised, however the scale of the fall was unexpected.

A new field development plan and reserves estimates are being currently being prepared and expected to be published within the coming months. Capital investment to stem the decline is expected, however given the low level of the FY2017 production guidance, this spend could be some way off.

On a more positive note, production from the DNO-operated Tawke field is budgeted to increase to 115mbopd from 107mbopd (2016).

On the Miran and Bina Bawi gas fields, Genel continues to seek a partner to help develop the resources, but management expect to recognise an impairment charge on this asset in the 2016 year end results.

Despite the issues facing Genel, the company still holds a large resource and remains one of the largest Kurdistan focussed E&Ps. The gas resource provides significant upside with ample demand once local geopolitics allows for its development.

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