BP cuts its price in Premier deal
The major will take a much lower upfront fee with more to follow from production revenues and if prices recover
BP has significantly dropped the upfront costs for UK independent Premier Oil to buy some of its non-core UK continental shelf (UKCS) assets to try to help get the deal over the line. It has also agreed to retain a substantial portion of decommissioning costs, and while more cash will accrue post-transaction, it may not get all of the previously agreed price.
Premier announced in January that it would pay $625mn for BP’s shares in the Andrew Area field, ranging from 50pc to 100pc holdings, and its 27pc stake in Shearwater assets—as well as agreeing a $191mn fee with Korean-backed producer Dana Petroleum for an additional 25pc stake in the Tolmount Area that Premier operates.
But it will now pay BP just $210mn, with a further $300mn going to the major in retained production revenues post-transaction. The outstanding $115mn from the original fee will “only become payable based on higher future oil and gas prices”, says Premier. BP will also retain 100pc of Shearwater’s decommissioning liabilities and 50pc of Andrews’, reducing Premier’s pre-tax abandonment costs bill from an initial c.$600mn to just c.$240mn.
Peace breaks out
Premier aims to fund the deal through equity and has also settled a dispute with its largest creditor, Hong Kong hedge fund Asia Research and Capital Management (ARCM), over plans to push back repayment of its bonds which has raged since it first struck the deal. ARCM will withdraw its lawsuit and will buy 82.2mn new Premier shares, or 8.9pc of the enlarged share pool group at just under 26.7p/share—a 9.6pc discount to the volume weighted average price over the last five days.
ARCM will use the share purchase to offset some of a short of almost 17pc it has built up on Premier shares and has agreed not to increase its short position further. It has also assented to Premier waiving its financial covenants through to the end of 30 September—described by Daniel Slater, oil and gas research director at London brokerage Arden as “helpful breathing room”—and to provide continued access to its revolving credit facilities.
$210mn – Premier will pay BP
As well as ARCM, the producer says it has secured the backing of creditors holding over 40pc of its debt. Securing creditor backing is key to the deal progressing on its revised terms.
“In our view, this all represents good progress for Premier,” says Slater. “While [it] will still leave a substantial equity raise to be executed, this was the case when the acquisitions were announced originally in January 2020, when it was envisaged to raise $500mn, albeit at much higher share price levels.
“Dilution could now be greater depending on exactly where the equity raise is done,” he continues. “But nevertheless there is now a route to completing the BP portion of the acquisitions—there is no update on the potential increased Tolmount interest—accessing higher cash flows and accelerating the use of Premier’s $4.1bn UK tax loss position.”
Ringing the changes
BP and Premier are not the only players to have had to make alterations to the terms of North Sea deals of late. Having announced they were teaming up to buy a package of UKCS assets being divested as non-core by Total in July last year, Neo Energy, backed by Norwegian private equity firm Hitec Vision and Oman’s Petrogas, announced in May that the deal had been revised.
Petrogas dropped out but Neo will proceed alone, while terms have also changed. Clearly, price was again important. No figures were made public, but Total admits the new deal “retains [only] the majority of the value of the [original] transaction”. And interest-bearing vendor financing and earn-out arrangements have been added into the provisions to get the deal over the line.
The exit of Petrogas from the buying joint venture is a potential concern for the health of the North Sea M&A market. Observers have suggested new entrants could emerge from regions such as the Middle East as well as South, Southeast and East Asia and could be NOCs or private sector firms. As, ultimately, a family-held Omani firm, Petrogas ticked some of these boxes, and its decision to walk away is not a ringing endorsement of a wave of buyer interest from the east.
And if the buyer pool remains limited, what then of the long-term intentions of Hitec Vision and other private equity investors? On the Norwegian continental shelf (NCS), the Var Energi joint venture with Italy’s Eni now controls all of the old ExxonMobil Norway portfolio, having last year bought the non-operated business to go with the operated fields it snapped up in 2017. When put alongside Eni’s assets, Var trails only the incumbent giants Equinor and Petoro on the NCS.
The 25,000bl/d of Total assets would put the combined Petrogas Neo into the top 20 UKCS producers, Hitec Vision said in its announcement of the original deal—although the 2019 production estimate was revised down to 23,000bl/d in its May release on the changes to the transaction. Its aim last July was to build a 100,000bl/d UKCS business.
Hitec Vision was active in the last big North Sea private equity boom in the 2000s. But it exited those investments in the conventional way—IPOs for Revus Energy and Noreco and a trade sale of Spring Energy to Anglo-Irish producer Tullow Oil. Neither route seems immediately available for Neo, so it may be that Hitec Vision is going down an alternative road of more patient private equity capital and rewarding investors through dividends rather than lucrative exit.
Var may be more sellable, given the NCS is much more concentrated than the UKCS and the costs of entry are greater. If someone wants to build or significantly expand an NCS business, there are not going to be many options. But the partnership with Eni is a complicating factor. And when the non-operated tranche of ExxonMobil assets came onto the block last year, analysts were not identifying a long roster of enthusiastic potential buyers.
Holding the baby
One firm seeing difference between UKCS and NCS assets is Israel’s Energean, which faces being left with previously unwanted North Sea holdings after the collapse of another agreed deal. The company had struck an agreement to sell stakes in the basin—which came as part of a package it agreed to buy from Italy’s Edison in July 2019—to the UK’s Neptune Energy, another private equity-backed producer.
“In our view, this all represents good progress for Premier" Slater, Arden
But Neptune in May agreed to pay a $5mn termination fee and walked away from the $250mn purchase. Given the macroeconomic environment generally and concerns over producers’ balance sheets, Neptune’s move is perhaps not surprising. Terminating the Energean deal “will further enhance our near-term liquidity by c.$460m”, Neptune says.
For its part, Energean is now discussing amending its original deal with Edison, where it may agree to take on the Italian firm’s UKCS assets, which include a 25pc stake in the large Central North Sea Glengorm discovery and a 10pc share of the Isabella find, but seeks to exclude its NCS holdings from the deal.
There are also sales processes which had not reached consummation that will be impacted by the turbulence of the last three months. UK utilities Centrica and SSE had both pitched the ‘for sale’ sign on their upstream businesses, while private equity firms Blackstone and Blue Water Energy had circulated a prospectus to potential buyers of their Siccar Point Energy investment according to documents seen by Petroleum Economist. Unconfirmed reports also put another private equity vehicle, Zennor Petroleum owned by Kerogen Capital, in the frame for a sale.
The utility exits may fall into a similar category to BP’s Premier deal, in that willing sellers of identifiably non-core assets may be keen to proceed assuming they can find buyers prepared to pay a price lower than what was initially assumed but acceptable in terms of getting a deal done.
The private equity exits look less likely to move forward, unless one of the prospective sellers is in urgent need of capital to return to investors. Given the chances of achieving a premium price are slim, owners must be expected to sit tight on their assets if possible and wait it out for better conditions in the future.