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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