Endeavour endangers Alba sale for Statoil and Mitsui

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

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

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

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

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

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

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

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

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

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VNG to evaluate options for its Norwegian E&P business

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

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

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

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

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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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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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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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International Petroleum Investment Company: A fresh start

IPIC has been on a journey to rebuild its business following the extraordinary downfall of Khadem al-Qubaisi, the company’s managing director who was made to step down in April 2015. In the months that followed, there was a major shakeup across all levels of the organisation including in the portfolio companies, with many of the roles previously held by al-Qubaisi reassigned to new officers. At the time, IPIC did not release any statements around al-Qubaisi’s dismissal, but in the months that followed, there was increasing newsflow in the media around alleged embezzlement of funds from business dealings between IPIC and 1MDB, a Malaysian sovereign wealth fund. Al-Qubaisi was arrested in August 2016.

OGInsights spoke with representatives of IPIC to find out more about the restructuring within IPIC. Suhail Mohammed Faraj Al Mazroui, the UAE energy minister, now heads IPIC with the group split into two divisions: Upstream and Downstream & Diversified.

The Upstream division is headed by Alyazia Ali Al Kuwaiti and includes the holdings in CEPSA, OMV and Oil Search.

Downstream & Diversified is headed by Saeed Mohamed Al Mehairbi  and includes the holdings in Nova Chemicals and Borealis and various business interests previously held by Aabar (including real estate and private jet businesses).

The IPIC team also act as source deals for Qatar Abu Dhabi Investment Company (“QADIC”), which is a joint Qatar and Abu Dhabi fund. The fund has a size of USD2 billion and aims to target investments with a link to IPIC’s downstream holdings. However, IPIC and QADIC will be cautious with making new investments given the recent tumult and will have plenty to focus on managing its existing portfolio.

In the upstream space IPIC will continue to look for acquisitions, which will be routed through CEPSA or OMV. IPIC aims to maintain a balanced portfolio with existing or near-term production / cash flow and keen to avoid heavy capex commitments. Africa remains a keen focus area (excluding Nigeria) as is Latin America, which will neatly complement the CEPSA portfolio.

In the downstream space, North American chemicals and fertiliser businesses are of interest. In Europe, only specialty chemicals are seen as a good fit (i.e. with Borealis).

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Siccar Point is building up its business

OGInsights recently caught up with the Siccar Point team following its successful acquisition of the OMV North Sea business, which includes an 11.8% stake in the flagship Schiehallion oil field. Together with the acquisition of a stake in the Mariner field earlier this year, Siccar Point has now built up a North Sea business of relevant scale.

Siccar Point is a North Sea focussed E&P, with financial backing from Blackstone, Blue Water Energy and GIC. It was set up in 2014 and after extensive screening of the North Sea over the past two years, the team are pleased to have finally closed a couple of transactions – the team have looked at over 50 potentially acquisitions including, not surprisingly, the ConocoPhillips and Shell North Sea assets.

The minority, non-operated stake (8.9%) in Mariner was acquired from JX Nippon with expectations of first oil in 2018. However, it was clear that this was only a first step to building a bigger North Sea business, which a small stake in a single asset is not. In that regard, the OMV package came along at an opportune time.

Having looked at the Shell North Sea assets, Siccar Point and its owners/financiers believed it was best to pass on the opportunity. As well as being a large portfolio for someone the size of Siccar Point, the substantial number of gas assets and attempt to package in the stranded Corrib asset offshore Ireland, made it strategically less attractive. The decommissioning liability that would come along with the Shell portfolio was also challenging. The OMV portfolio, which came with a smaller number of long life assets was therefore much more desirable.

The financing of North Sea assets has been an ongoing challenge for vehicles such as Siccar Point which are backed by private equity money. The business model requires for acquisitions to be financed with substantial amounts of debt, and in most cases, the amount of debt that can be raised is based on the amount of reserves. However, the UK has a regulatory regime which requires operators to provide financial guarantees (generally in the form of letters of credit) for decommissioning liabilities – these are now coming to the forefront of attention given the maturity of the North Sea and imminent or near-term cessation of production across the basin. These guarantees consume much of the debt capacity and therefore require larger cash or “equity cheques” to be fronted by acquirers. Ultimately the OMV North Sea portfolio was one that worked well for Siccar Point in terms of size and ability to finance.

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BP: Adapting to the times - Where were they now? (Part 2)

The OGInsights team recently met with the BP corporate strategy department to discuss how the strategic direction of the company has changed since the collapse in oil prices. In this two part entry, we look at where BP were a year ago and where they are now in terms of strategic thinking.

Part 2: Where are they now?
With oil prices appearing to stay lower for longer, BP’s priorities have changed and all large M&A is on hold. Focus is on cost cutting, targeting breakeven of USD 50-55/bbl over the next year and farming down high working interests and material exploration commitments.

On the opposite end of the scale, the BP team remains busy on divestment with a target of offloading USD 3-5 billion this year – this compares with a run rate of USD 2-3 billion per year for BP. However recognising the oil price environment, divestments are aimed at non-oil price linked assets, namely midstream and refining. BP shared that there are no country exits on the mid/downstream side, so the portfolio tidy-up will very much be pruning within the portfolio.

As oil prices recover, BP will begin looking at reshaping the portfolio for the longer term and the focus will be on OECD assets (i.e. as opposed to companies like Tullow, which BP have been reported to be monitoring for years). Of note, BP noted that any material acquisitions will likely be in US tight oil, where BP see a clear gap compared with its peers. Oil sands are a “no” following COP21 and despite other majors investing in renewables, there is currently no interest in this area given the loss making nature of this division historically.

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BP: Adapting to the times - Where were they then? (Part 1)

The OGInsights team recently met with the BP corporate strategy department to discuss how the strategic direction of the company has changed since the collapse in oil prices. In this two part entry, we look at where BP were a year ago and where they are now in terms of strategic thinking.

Part 1: Where were they then?
At the beginning of 2015, BP already began planning for a "lower for longer" scenario, however growth was still very much top of mind. Reserve replacement was a key challenge to the company's longer term existence and the USD2 billion annual exploration programme at the time, assuming a USD5/boe finding cost, would only yield 400mmboe of new reserves compared to BP's annual production of c.750mmboe. BP wanted to maintain a quality exploration programme, but it was increasingly recognised that M&A would be needed to meet the necessary level of reserve replacement.

In terms of M&A, BP were looking for "scale and materiality" and needed to be in a position where it would be relevant to a country. They shared a few key themes of their strategic thinking back in 2015, with a focus on their African portfolio:

1. Existing portfolio sufficient

• They were satisfied with their positions in Africa (Angola, Egypt, Algeria) and did not see other opportunities in the region of sufficient scale to justify a new country entry.

2. Brazil over West Africa

• Although the West African Transform Margin was an attractive play, BP's position in the conjugate Brazil offshore was seen as an easier play on the geology without the need to deal with multiple countries/governments along the West African coast.

3. Angolan monetisation

• Angolan geology was clearly a coveted part of the African portfolio, and in 2015, BP were reaching a critical phase of exploration testing with a series of wells in the year (which were technical successes).
• However, the Angolan position was littered with a lot of stranded discoveries and could not be developed on the current cost base.
• Options to monetisation being considered were sharing of costs, or acquiring to build critical mass there.
• Acquiring Cobalt was clearly something being considered.

4. Rebalancing to the onshore

• The company's portfolio was viewed as over exposed to deepwater and not the balance BP would like to be in a low oil price environment.
• They were glad to have missed out on East African gas story which has been plagued by delays and upcoming expensive developments.
• Tullow and Africa Oil continue to be monitored in the background, as an opportunity to rebalance the onshore portfolio, and NewAge's Congo position and Savannah Petroleum in Niger were added to the company's M&A screening hopper as emerging candidates.

In Part 2, we look at how BP's strategic direction has changed since 2015.

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ExxonMobil - finding a needle in a haystack

We met with ExxonMobil in the first week of December to catch up on what they have been up in 2015 on the M&A front. The low oil price has certainly prompted an internal flurry of screening for targets and the teams have been looking at “a lot of opportunities” with billions of dollars ready to be spent on acquisitions. Despite a desire to do something, finding the right opportunity is still like “finding a needle in a haystack”.

ExxonMobil’s corporate development team is split into two divisions – Upstream Ventures which look at deals up to USD20 billion and Corporate Strategic Planning which look at deals above USD20 billion. Acquisitions broadly fall into three categories which are generally independent of size:

• Bolt-ons – these are generally small acquisitions to supplement an existing position although larger acquisitions will be considered on a case-by-case basis 
• Expansions – these are to materially grow an existing position into a wider position; size is opportunity specific and considered on a case-by-case basis
• New entry – these are always sizeable acquisitions as they must have sufficient critical mass in order to establish a new position

Outside of North America, Africa and the Middle East are regions of keen interest and we discussed two themes around current market developments.

The Africa Oil farm-out to Maersk was viewed as interesting and ExxonMobil remarked that more innovative structures, such as the one adopted by Maersk, was likely needed to get deals which weren’t clear winners over the line in the current oil price environment. East Africa is an area which ExxonMobil’s technical team have evaluated before and they remain cautious on the prospectivity (noting that no-one outside of Tullow/Africa Oil has been successful in the region) and timing to first oil (given the export pipeline infrastructure is yet to be built).

On Kurdistan, ExxonMobil are comfortable with the region geologically but see very few opportunities of sufficient size to justify building up a full-scale presence. This likely limits the opportunities to a handful such as Genel and Gulf Keystone. Payments for exports by the Kurdistan Regional Government remain a key issue and ExxonMobil noted that any slippage of payments could severely depress project economics as well as delaying any development spending. The Kurdistan Regional Government have implemented payment schedule on multiple occasions in the past which subsequently collapsed and it yet remains to be seen whether the current payment plan, implemented in September 2015, can be sustained.

ExxonMobil will continue to scour the international E&P landscape for opportunities and believe that current environment is a good time to act, but finding the perfect opportunity remains a challenge.

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CNOOCNexen on the prowl

Last week, we met with the CNOOCNexen corporate team to discuss their thinking in the current low oil price environment and the possibility of using the opportunity to make acquisitions.

At the beginning of 2015, CNOOCNexen expected oil prices to settle at c.USD60/bbl and the second drop in June came as a surprise. Similar to the view held by many oil companies, the oil price is now lower for longer than originally anticipated. CNOOCNexen anticipates oil prices in 2016 to be similar to 2015 levels.

The company’s UK portfolio, which mainly comprise of its 43.21% interest in Buzzard and 36.54% interest in Golden Eagle, is in a relatively good place with operating costs of below USD20/bbl. While the UK operations are not making a fortune at current oil prices, it is keeping its head above water which is more than what can be said for many North Sea fields.

M&A remains on the radar with Beijing head office looking for opportunities in the UK, Brazil, West Africa and Southeast Asia. In fact, the UK North Sea has been cited as one of the top desired areas for further investment and growth. Corporate and farm-in opportunities at all stages of the lifecycle from exploration through to production are of interest. CNOOCNexen did not disclose their oil price assumptions for evaluating acquisitions, but noted that they are beginning to see convergence between buyers and sellers in the market. In terms of acquisition size, USD5 billion would be the top end of what could be do-able. However, CNOOCNexen are still waiting for some stability in oil prices and cost indices before they can feel comfortable with valuations internally and start to make moves.

In the UK North Sea, acquisitions would be to “keep the engine running” rather than building a new business. CNOOCNexen are looking for assets where there is scope for upside and their team could add value; in this regard, assets which have demonstrated reserves creep are of interest such as Apache’s Beryl field and Shell’s Pierce field. Upcoming disposals from the majors, whether piecemeal or as a portfolio, are opportunities coming to market that CNOOCNexen are keeping a close eye on. Development assets are not ruled out given the current North Sea portfolio is in a tax paying position and development expenditure could be used to offset against profits. CNOOCNexen are now beginning to explore heavy oil opportunities as the size of the resource and progress in developing technology to exploit heavy oil (such as by the likes of Statoil) means it can no longer be ignored as a strategy. 

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