In January, Norwegian independent DNO had an improved 160p/share offer for Aberdeen-headquartered North Sea E&P firm Faroe Petroleum accepted, following a previous 152p/share bid late last year.
Just as that union was consummated, press reports emerged spotlighting UK independent Premier Oil as a prime candidate to buy North Sea assets on the block, following US major Chevron's decision to sell off its portfolio in the Central North Sea and potentially its stake in Clair in the West of Shetland (WoS). In December, private equity-backed Chrysaor was also linked with a move for Chevron's assets.
The three-month exclusivity deal into which UK petrochemicals heavyweight Ineos entered to negotiate to buy North Sea assets from US independent ConocoPhillips is expected to expire in February, while Total was widely reported to have put assets worth $1bn+ up for sale in the middle of last year, although this was never confirmed by the major.
All of this adds up to what could be another year with a significant number of M&A transactions, although consultancy Wood Mackenzie does caution that deal spend may slow.
DNO's unusual North Sea history makes it challenging to extrapolate any generic trends from its specific acquisition. The firm was founded as far back as 1971, but its ambitions at home were thwarted by a 1980s government decision to facilitate just three domestic firms on the Norwegian continental shelf (NCS). Thus, it concentrated on international growth until the opening of the NCS allowed it to re-enter in 2004. Subsequently it merged its NCS assets with Norwegian independent Pertra and split its domestic and international activities into the rather indistinctively named Det Norske and DNO International.
In 2009, Norwegian services giant Aker merged its upstream arm into Det Norske, pushing DNO's stake down to just 25pc. Yet another merger, with the NCS assets of BP, created Aker BP and DNO exited its shareholding, only to set up another NCS subsidiary in 2017. In short, DNO has a unique back story, not easily comparable to any other North Sea player.
One aspect of the Faroe acquisition that does bear scrutiny is the price DNO paid. While it had to up its initial offer by 8p/share, brokerage Arden was still advising Faroe shareholders to reject 160p and had a 180p/share target on Faroe stock. Its risked exploration net asset value (Renav) for Faroe was 183p, while investment research firm Edison put the Renav slightly higher still at 185.2p.
Arden outlined three scenarios if Faroe shareholders reject the second bid—an increased third bid, DNO walking away and Faroe retaining its independence, or another potential suitor emerging. But it noted, on the final alternative, that "peer-to-peer M&A is not a great sector theme at present".
The lack of another interested party in Faroe may not, though, be that surprising, says Sanjeev Bahl, senior analyst at Edison, given that DNO already held a 30pc stake in Faroe. "If you were another hostile bidder, it would have been slightly more difficult for you as a third party dealing with the other Faroe shareholders and with DNO," says Bahl.
DNO's relative high cash pile, giving it a lower cost of cash than some of its peers, was also likely to give it an edge over would-be competitors, given the sensitivity of Faroe's valuation to cost of capital, he continues.
While a fairly narrow slate of buyers is a potential risk to North Sea M&A activity, Wood Mackenzie remains fairly bullish, seeing "a pool of buyers eager to grow". Asian NOCs and listed independents "cannot be ruled out, but most roads lead to the wave of privately backed/owned companies", it says.
Most of the acquisition opportunities will require deep-pocketed buyers, Wood Mackenzie predicts. It sees those firms among the privately-funded recent new entrants that are more willing to take on assets throughout the value chain, rather than those with more organic growth stories, as the most likely big buyers.
Japanese E&P firms formed a past wave of North Sea entrants, but that was largely in a pre-shale boom world when easy access to prospective resources on relatively attractive terms in politically and fiscally stable areas were expected to be at an ever-growing premium. With US shale acreage remaining available as an investment opportunity, it is difficult to see a class of non-western European producers rushing to the North Sea en masse, and Wood Mackenzie's caution seems justified.
Its question mark over listed independents as significant M&A players is also understandable, but would be dispelled should Premier pull off the Chevron deal with which it has been linked. It remains, though, a substantial if.
Premier issued a statement noting speculation regarding the possibility of it making a UK acquisition, saying it will continue to look at opportunities to acquire UK North Sea assets, but offering no guarantee that it would bid in any process. It specifically denied taking a firm decision to bid for any or all of Chevron's holdings.
It was also explicit that, should it make a successful bid, it had made no decision on financing the acquisition. One press report had mentioned a rights issues to fund the bid, which caused a 11.5pc swoon in the firm's share price in the following day's trading.
Funding an acquisition that, if it included all of Chevron's assets, could well get close to the $1.5bn mark is clearly an issue for a company that has a market capitalisation of just over £571mn and an existing $2.33bn net debt position which had to be extensively renegotiated as recently as 2017.
"We would … not be surprised if a transaction of this size required a substantial equity element. On this basis, buying Chevron's assets just seems too large a deal for Premier to achieve, in our view, without some sort of innovative structure (such as that used by [fellow UK independent] Serica in its Bruce/Keith/Rhum deal, which left sellers with an ongoing cash flow interest)," says Arden.
Another analyst, who preferred to remain anonymous, agrees that the market took fright about the prospect of a rights issue. He sees Premier as a credible buyer operationally, given that it is the operator of Catcher and its peer Serica operates Bruce/Keith/Rhum. "We have seen these relatively smaller companies trying to bite off big packages—they can do it operationally, it is harder financially," he says.
The firm could, in his view, do with another 6–12 months "to sort its balance sheet out", before attempting a deal the size of the Chevron transaction. "Premier could look at buying with a mix of debt and equity, but it would have to put in much more equity than normal—that would be the only way to do it," he says, while also questioning Premier's ability to successfully execute a rights issue.
Decommissioning liabilities are also a factor, as, in the event of sale but the subsequent collapse of the buyer, these would rebound back along the chain to Chevron. So the US major is likely to prefer to deal with a buyer where there is as near zero a chance of bankruptcy as possible, and "Premier at this point is not that buyer", the analyst cautions.
Edison's Bahl is more sanguine about Premier's chances, despite noting that the firm's net debt to EBITDA ratio is around three and it is committed to bringing it down to 2.5. As long as the deal is "covenant accretive"— that is, while it increases debt in absolute terms, the increase in EBITDA relative to the additional debt is sufficient to actually bring the ratio lower—he feels the deal is viable.
One attraction of the Chevron package is that, alongside stakes in ageing Central North Sea fields, it is widely thought to include the firm's almost 20pc stake in the Clair field in WoS, which is less than 15 years old, saw a new development stage that has just come on stream and has a potential third phase to come.
This juicier morsel may be key to attracting buyers, just as Shell's portfolio that it sold to UK independent Chrysaor in 2017 included its share in the relatively modern Buzzard oil field alongside older assets. Norway's Equinor was a willing buyer of Chevron's 40pc operating interest in the undeveloped WoS Rosebank discovery in October.
It is difficult to say for certain what Total may have for sale, given a lack of confirmation from the French major. But press reports from the middle of last year pointed towards two separate sales processes, one for a 20pc stake in the WoS Laggan-Tormore gas field and the other for a raft of stakes in other fields, many of which were part of its own 2017 acquisition of Denmark's Maersk Oil. Golden Eagle, Dumbarton, Bruce and Keith were mentioned specifically.
The Laggan-Tormore stake could be attractive, particularly for any firms needing to replenish European gas supply portfolios. But a number of sources have raised concerns about the potential saleability of the other package of assets discrete from Laggan-Tormore. "It has not got anything nice in it," says one bluntly.
Another deal around which it is difficult to get confirmed facts is the widely reported Ineos bid for ConocoPhillips' North Sea assets. But a close observer of the career of Ineos' CEO Jim Ratcliffe says his reputation is for paying prices for assets that most observers see as too high, but mostly making the deals work. This give him confidence that Ineos will likely make an offer sufficient to get the ConocoPhillips transaction done.
With Shell, ExxonMobil, which sold its NCS operations to privately-held Norwegian producer Point Resources in 2017, and possibly Chevron, ConocoPhillips and Total all selling significant chunks, if not all, of their North Sea assets, attention inevitably turns to BP's intentions. The UK major has sold assets in recent years to firms such as Ineos, UK independent Enquest and Serica, and divestment remains firmly on the firm's mind.
At its third-quarter results presentation at the end of October, BP talked of its intention to hit its $3bn divestment target for the year, despite having made only $0.4–0.5bn of assets sales up to the end of Q3. While it said to expect at least announcements of further deals by year end, it has yet to make public any additional divestments. Above this 2018 overhang and 2019 business-as-usual divestments, BP is also slated to complete the first tranche of its $5–6bn of sales over the next two-to-three years announced in the wake of its purchase of UK-Australian producer BHP's US shale assets.
"Quite gassy and legacy" parts of the portfolio will be the focus of these deals, which could apply to some of BP's remaining North Sea holdings. But the firm has thus far taken a much more piecemeal approach to selling UK assets compared to peers that have put swathes of assets on the block, reinforcing analysts' impressions of BP as a savvy dealmaker, extracting greater value from individual stakes, whereas a package of assets often leads to discounting.
The firm has also taken innovative approaches such as the Serica Bruce-Keith-Rhum deal, where BP retained future upside through agreeing to a share of cash flows over the following four years and several contingent payments dependent on future asset performance and product prices—in contrast to, for example, Shell's Chrysaor deal where Shell retained future upside, but of a more debt-like nature due to its role in financing Chrysaor's buy. Also, in Norway, BP rolled its portfolio into Aker BP, reducing its hand-on involvement, but retaining a 30pc equity stake.
BP's status as the highest-profile solely UK-headquartered major might also be expected to have some bearing on how it approaches possible North Sea divestments, in addition to solely economic rationale. And it is not only a reputational concern—industry bodies point out that it is advantageous for BP as a UK company to have operational interest in home waters from a technical training and development perspective, rather than having to send trainee staff abroad.
But Edison's Bahl would not be surprised if BP made another move to recycle capital from North Sea assets nearing the end of their life that remain in its portfolio. "It is just the maturity of the basin, they will continue to monetise smaller, more mature sub-10,000bl assets," he predicts, while expecting them to maintain a North Sea presence in larger developments with remaining growth potential such as Clair and Schiehallion.
A final element within the UK North Sea's M&A picture is the tax loss position—where production revenues are sheltered from tax by historic exploration, appraisal and development losses—held by several of the listed independents. These positions could assist with any acquisitions on their holders' part of older producing assets, but could also make them attractive targets, particularly for potential suitors with tax-paying assets already in their portfolios.
Premier has the largest of these positions both in absolute and relative terms, with Arden putting the figure at $4.1bn. According to one analyst, Brent crude could rise to $90/bl before Premier would begin to pay tax on its existing production and, even then, not immediately. Others, such as Cairn Energy and Hurricane Energy, also hold material tax loss positions.
The shield offered by Premier's tax position would be an obvious cashflow benefit should it move forward successfully with a Chevron deal. But if a company with tax-paying assets could find a way of bolting Premier onto their portfolio, that too could be the driver for an acquisition.
Edison's Bahl is unconvinced that Premier is more likely prey than predator. "It has got quite a diverse asset base, I cannot really see someone buying Premier just for its UK tax losses. Historically it has more been in the market to buy assets, like its OilEx deal, in order to utilise its tax position, and has even successfully re-organised to spread its tax advantages across its business," says Bahl.
The UK's HMRC tax authorities would also be highly unlikely to experience a sudden slump in the revenue take from a firm with taxable production in the wake of a purchase of a company carrying tax losses without taking a very close look. So making such a deal purely to try to realise tax benefits could be a risky undertaking.
Nonetheless, analysts feel that there could be ways to structure the transaction so as to pass muster with HMRC. "What do you pay very expensive tax accountants for, if not for something like that?" asks one.