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    Even if the terms can look tough, bankers are warming again to Financing the upstream minnows [NGW Magazine]


The smaller end of the upstream sector is thriving, although not so much as many producers would like, bearing in mind the relatively high oil price.

by: William Powell

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Top Stories, Premium, NGW Magazine Articles, Volume 3, Issue 22, Exploration & Production, Investments, Financials, Market News

Even if the terms can look tough, bankers are warming again to Financing the upstream minnows [NGW Magazine]

The smaller end of the upstream sector is thriving, although not so much as many producers would like, bearing in mind the relatively high oil price. A conference in London organised by 121, which brings together investors and producers, heard that while the share values of the majors such as BP and Shell have tracked the oil price, the shares of even debt-free small players are discounted by 45% or more.

So the market should be ripe for consolidation and investment should flow in with an eye to future growth while stocks are comparatively cheap; but a number of buyers including pension funds are diversifying away from oil and gas. This is partly because the tide of public opinion is turning away from fossil fuels, and renewables are on the way up, possibly offering rich pickings.

And some investors are still “shell-shocked” after the last crash and they are still undervaluing assets, said Richard Redmayne, a director of corporate financing advisers SP Angel specialising in oil and gas.

Nevertheless, there are many companies with compelling arguments for investment, once the initial hurdles have been surmounted.

Getting a strong management team in place and the story right are key requisites, especially when the aim is a short-term exit – which is a commoner strategy in North America than in Europe: LetterOne’s Christian Coulter, a principal at subsidiary L1 Energy, said that he would like to see more of the “four to five years and then flip,” approach, rather than long-term investments.

For some companies, business is ticking over nicely and they do not seek to do much more than turn in a decent profit each year. But others are more ambitious, and they have reached that stage in their development where they need to raise more equity in order to grow their business substantially if they are to reach their next stage, whether that is to ramp up production to meet local demand for gas, or to sell up altogether.

Russian-owned L1 owns DEA and, putting his money where his mouth his, Coulter said the merger of Wintershall DEA, due for completion in the first half of next year would create a major oil and gas producer. He expects an initial public offering within 18 months of merger approval “unless something else happens.”

Other private-equity backed companies who have entered the likely seeking an exit in a few years’ time include Neptune, Siccar Point and Chrysaor, who have all bought assets in the North Sea.

A London listing is often the first step for raising equity through an initial public offering, where the alternative investment market (AIM) is generally open for equity business even where others are closed. London does value risk and you can raise money here. AIM is now 20 years old. “You can get funded, even if you do not like the price,” said oil and gas advisor Richard Hail of SP Angel; and once there is equity, debt will follow. He said the service sector was now very competitive as the “virtualisation” of the international oil companies had pushed out a lot of geologists and drilling experts.

According to Xavier Venereau, head of oil and gas producers and finance at BP in London, mergers and acquisitions are now back in vogue, but on a cautious footing. The downturn, which deadened the equities and high-yield bond markets of the pre-crisis years, has been succeeded by a flight to quality and innovative private equity deals. This is partly because of the greater uncertainty about whether next year’s oil price will be $80/barrel or $50/barrel.

On the positive side, the upstream business has seen a transformation in the last few years, according to consultancy Wood Mackenzie’s vice-president for global exploration Andrew Latham: the money spent has yielded a 50% return in terms of the discoveries made – he named the UK west of Shetlands and Guyana, as well as Australia’s Dorado find (see below); and most are in areas of the world where they can be monetised.

Offsetting that is the smaller size of the finds: the discovery rate might be the same, but the industry is not finding the giants it used to, averaging about 25mn barrels per well for the last few years and most of that has been onshore unconventional in North America – where all but the cheapest reserves lie fallow until demand rises, especially in Canada’s Montney. US shale and deepwater projects have been driving much of the growth, but there needs to be a lot more as the world’s future liquids supply will have to come from reserves yet to be found, he said.

Still there are hurdles to overcome before investors will reach for their cheque-books. A panel discussion that focused on Africa, but with conclusions applicable elsewhere, said that a company looking to raise outside capital needed to have a route to market and certainty of payment; certainty of title and the legality of its acquisition; a clear strategy of execution and having the right people with the right experience in place; and good relations between management and local partners.

Even then there are no guarantees: as Canadian producer Questerre found out when Quebec imposed a ban on hydraulic fracturing, despite the province’s gas deficit, slashing 30% off the share price before the new regional government came in and changed the rules.

Many of the companies had a coherent story to tell about their development plans, either fitting into a market short of gas; or one where it fetches a good price; or carving out a market for themselves to exploit – preferably in a country that has a benign and stable investment regime. Not all were there actively seeking financing; but keeping the company in the front of investors is seen as important in a generally picky market.

AIM-listed duo SDX and Sound Energy fit into this model, both drilling wells in Morocco, which currently receives 90% of its gas from Algeria through the pipeline to Spain, Gazoduc Maghreb Europe (GME). The power market is only 800 MW but is forecast to reach 3.2 GW by 2030.

In both cases, they are partnered by the state power company which takes the state’s share of the profits, but no direct taxes or royalties apply otherwise for ten years. This contrasts with other African countries such as Angola and Algeria, which have in the past failed to attract investors to their licensing rounds by taking a biased approach to risk and reward. Extracting very high value from the IOCs, the latter voted with their feet in later rounds in Angola and only local firms picked up blocks. The balance of power in Angola has now swung back again towards foreign investors, according to one speaker, the lawyer and financier Nicolas Bonnefoy of Africa Oil & Gas.

In the case of SDX, the Moroccan market is local industry: French car manufacturer Peugeot-Citroen has a plant in Morocco and there are other factories that make parts for the cars too, such as windscreens.

The gas price is linked to dated Brent, but with a minimum of $40/barrel and a maximum of $80/barrel; it sells at around $10-12/’000 ft³. The contracts are fixed price for five years and have no penalty clauses for under-delivery, the CEO Paul Welch told NGW. SDX bought Circle almost two years ago, giving it a business.

SDX received a loan of up to €10mn ($11.7mn) from the European Bank for Reconstruction and Development in July, for improving gas production and related gas transport infrastructure to Kenitra industrial zone customers. This enabled a switch from polluting fuel oil, potentially reducing local CO2 emissions by 20,000 metric tons/yr.

Sound is not yet in the production phase but with its former contractor and now equity partner Schlumberger it is drilling for gas in the south, and in the east. The Tendrara play was first drilled fifty years ago when it belonged to Eni’s upstream division Agip. The plans for the gas as yet are uncertain but the front-end engineering and design contract for a processing plant and a 120-km pipeline link to the GME is with a consortium that includes Spanish transmission system operator – and GME part-owner – Enagas. The company could export the gas to Spain, although the local power market would be a simpler option and could yield higher netbacks, judging by the prices that SDX is receiving. That plant and pipeline have agreed vendor financing of $186mn and Sound will pay a tariff of $45mn/yr for 15 years.

The plant and the pipeline will be financed on a build-own-transfer basis, which ensures that the infrastructure owners recover their costs from tariffs paid by the producer over a set period; and Sound is looking to take final investment decision in mid-2019, with first gas the following year.

Further south, Savannah is buying Seven Energy’s upstream and midstream assets in Nigeria, where gas at $3.50/’000 ft³ can compete easily with diesel which retails at three times that. More production and higher margins are the company’s goal there. And it sees 40 trillion ft³ of undeveloped gas reserves that must go through Nigeria’s Accugas pipeline system.

In Kenya, Midway is hoping that its own gas at Pate 1, near Port Lamu, can be used for micro-LNG, backing out the heavy fuel oil used in Mombasa; and to supply gas to a planned power plant. “Coal plans probably will not survive a decent gas discovery as close as we are,” CEO Peter Worthington said.

And there are companies – the UK North Sea has its fair share of them – that were set up by scouts who had worked for the majors, and are convinced that there is enough undiscovered resources to merit more work. For example, Talisman’s southeast Asia upstream assets were considered so promising that when Repsol bought it, the executives in charge of them went off to form a new company, Jadestone.

While it raised $110mn in London in August to purchase Montara, its own valuation looks low at just 45% of the assets’ value, said CFO Dan Young. Recently though, regional assets have begun to catch the eye of investors such as Austria’s OMV and UK independent Ophir Energy.

Other companies have such luck with the drill bit that their value is transformed overnight: such as Carnarvon, which discovered the 360mn (2C) barrels of oil equivalent (boe) Dorado oil/gas/condensate field on Australia’s Northwest Shelf (NWS). The third biggest find ever to be made there, and in only 100 metres’ water depth – jack-up territory, as CEO Adrian Cook puts it – it opens up a range of possibilities, including providing backfill gas for the Woodside-operated NWS LNG project. It catapulted the company’s share price from A$0.13 to A$0.60. Within a 30-km radius of Dorado are the Apus, Pavo, Roc and Roc South discoveries, the four adding up to 1bn barrels of oil equivalent, of which there could be 1 trillion ft³ of gas. Carnarvon has sold down its shareholding to 20% or 30% in the different blocks.

The likely plan, Cook told the conference, will be to start producing the oil to generate cash-flow, and then move to full field development. He said Woodside was looking for tolling gas as backfill for its LNG operations but that there are also onshore gas sales possibilities.