UPSTREAM RECOVERS ITS ATTRACTION
BP CEO Bob Dudley was unapologetic about expected higher capital expenditure in 2017 , as he unveiled the Q4 2016 results . Capex is now forecast at $ 16bn- $ 17bn , up from $ 15.5bn . “ We have a lot of additional new major projects on board ,” he said .
BP ’ s CFO Brian Gilvary said the major expects to have 800,000 boe / d new production from its new projects by 2020 . Much of this is based on asset deals , or longer or expanded licences – in Egypt ( Zohr ), Abu Dhabi ( Adco ), Oman ( Khazzan ), Azerbaijan ( ACG field ) and a farm-in to Kosmos ’ gas offshore northwest Africa – that had been worked on for months but chanced to coincide late last year .
Also this week Delek mounted an offer for the 80 % of Canadalisted North Sea developer Ithaca Energy that it does not yet own . Its offer price implies Ithaca ’ s value at 100 % at £ 1bn ( US $ 1.24bn ) – even though its key asset is a North Sea field that won ’ t come onstream until later this month – some 3 months behind schedule , and it paid a big premium to the preannouncement share price .
ExxonMobil , Noble Energy and US fund Blackstone Energy Partners too spent a total of $ 12bn on three shale oil and gas acreage deals based on Texas / New Mexico in the space of just one week in mid-January ( NGW Vol . 2 Issue 2 , p28 ).
So was BP going to reject these just to maintain capex discipline ? To paraphrase quiet man Dudley : “ Hell no !” Analysts on its results call joshed about “ BP filling its boots ” with growth assets , as Dudley and his CFO sounded only mildly disapproving of brash language .
Gilvary though pointed to higher year-on-year gas and oil prices in 4Q , with Henry Hub gas at $ 3 / mn Btu ( from $ 2.30 ) and Brent at $ 49 / b . Before the Opec agreement , in 3Q 2016 Brent was $ 46 and it has since the start of December been trading between $ 54 / b and $ 58 / b .
Dudley also talked about BP ’ s expectation that a worldwide OECD oil inventory of 3mn bbls could be eroded by end-2017 , if Opec sticks to its latest production-cutting deal – which he had sensed will happen from his meetings with “ steely ” Opec and Russian industry chiefs .
Shell embraced The Big Deal when industry confidence was at its lowest . Its 2015 deal to buy BG , completed in February 2016 for $ 54bn , was seen as reckless by some , essential to repair its declining gas reserve base by others . It is now 50-50 oil and gas . But critically the value of the deal was tied to the oil price . Now Shell is already halfway through a $ 30bn divestment programme , selling mostly late-life ex-BG assets in the North Sea to newcomer Chrysaor ( see inside ). In some cases Chrysaor it has also become the operator , a position which can enable the extraction of more efficiencies . But these kinds of sales could create tension if other partners want to become operator . Still for now , the government ’ s initiatives to maximise the economic recovery of the North Sea appear to be working .
Analysts now see Shell getting good prices on such North Sea deals , as private equity and wealthier NOCs emerge from the oil and gas price doldrums to rebuild their upstream portfolios . Kuwait ’ s Kufpec has also been in buying mode , offshore both Norway ( from Total ) and Thailand ( from Shell ), while EIG again – this time in Australia – is to increase its stake in coalbed methane developer Senex , in return for up to $ 300m more funding .
The return of investor confidence and M & A activity featured in reports from technical advisers DNV GL and global consultancy EY . One region of the world where both saw little net investor influx was Africa . In some parts , like Nigeria , this is often because investors aren ’ t free to repatriate or reinvest profits earned ( see inside ).
DNV GL ’ s Vamadevan went so far as to say Africa , again , will not be an investors ’ priority in 2017-18 , and noted the slow progress towards a FID on Mozambique ’ s Coral floating LNG project . So perhaps it ’ s cheering to see renewed – if still some way from actual investor – interest in a neglected gas project off Africa ’ s southwest corner – and from an unexpected source : BW Offshore . It is to take a 56 % interest in the 1.33 trillion ft ³ ( 37.7bn m ³) Kudu gasfield 170 km from the coast . The gas would go to a new 885-MW power plant onshore Namibia .
The problem is that this project has been passed from pillar to post for a decade , and at times of higher prices too . Experienced Africa-focused UK independent Tullow and its Japanese partner Itochu relinquished their interests in the Kudu offshore licence in 2015 , saying the field ’ s gas was uneconomic to develop , whereas BW is aiming for a final investment decision late this year .
“ Falling development costs after the 2014 drop in oil prices has helped in making the project economically feasible ,” insisted Arnet . As the BW Group extends from FPSOs to LNG carriers , it knows the hard way about low ship charter rates during the 2014-16 oil price slump .
While Shell no longer sees a huge North Sea upstream portfolio as prudent , clearly Chrysaor and Delek see value in holding production close to dependable OECD markets . And just as Tullow saw no role for another risky Africa project in their portfolio , so maybe – just maybe – Singapore-based ship specialist BW may find a way forward to monetise Kudu , 43 years after Chevron found it .
NGW