Just a few years ago, when oil sold for about $100 a barrel, banks here were lining up to give international oil explorers access to billions of dollars to finance new drilling and projects.
But as oil prices stay mired in a funk, the money is drying up.
Senior executives from companies such as Tullow Oil TUWOY -2.91 % PLC and Cairn Energy CRNCY -1.03 % PLC have been meeting with their bankers for a biannual review of the loans that allow them to keep drilling and building out projects. For many European companies, it has been a nail-biting experience, as banks worry about the growing pile of debt taken on by oil companies with little or no profits. Several companies said they expect their ability to tap credit lines to be diminished after the reviews.
Some lenders have brought in teams that specialize in corporate restructuring to scrutinize companies’ balance sheets, spending and assets, though not at Tullow or Cairn, a person familiar with the matter said. In the past, the reviews were generally conducted solely by banks’ energy specialists.
The new scrutiny in Europe comes as oil-company debt emerges as an issue across the world with prices for crude near $40 a barrel—down more than 60% from June 2014. Globally, the net debt of publicly listed oil and gas companies has nearly tripled over the past decade to $549 billion in 2015, excluding state-owned oil companies, according to Wood Mackenzie, the energy consultancy.
Reviews of these loans have high stakes. If a bank decides a company has already borrowed more than it can afford, the reviews could trigger a repayment, more cost cuts or even a fire sale of assets to raise cash.
Many of the reviews have concluded, or will soon, and the results could be known as soon as this week.
“There isn’t anyone in the oil independent sector that will be very relaxed at the moment,” said Thomas Bethel, a partner specializing in energy finance at Herbert Smith Freehills LLP.
Oil companies are facing a similar set of biannual reviews in the U.S., where many small and midsize companies borrowed heavily to expand during the shale boom. The number of energy loans deemed in danger of default is on course to breach 50% at several major U.S. banks, The Wall Street Journal reported last week.
But some American firms have been able to raise cash by issuing new stock or selling new debt, while in recent years Europe-based explorers have come to rely more on bank lending as investors that once pumped up the industry are fleeing in droves.
In Europe, the focus is on a specialized type of borrowing known as reserves-based lending that has mushroomed in recent years. Europe’s top 10 non-state-owned oil companies have taken on over $12 billion in such loans, which are particularly exposed to energy prices as they are secured against the value of a company’s petroleum reserves and future production.
At Tullow, Chief Financial Officer Ian Springett said he thinks the company could lose some ability to draw on its $3.7 billion credit line with its banks. Cairn expects its banks will allow it access to only about $335 million of the $400 million in credit that was once available.
“When oil was at $100 a barrel, debt was easy to get,” Cairn Chief Executive Simon Thomson said in an interview. “What we’re seeing today is a number of people suffering the hangover of having secured that debt and now possibly having trouble servicing it.”
The stakes were underscored in February when First Oil Expro, a subsidiary of the largest privately owned U.K. North Sea oil producer, called in the administrators—a process similar to filing for chapter 11 bankruptcy in the U.S. First Oil Expro was unable to meet its share of costs on one big development and was unable to keep up payments on loans in excess of $150 million.
“The key issue around First Oil Expro’s demise was the sharp fall in the oil price which led to a significant loss of confidence in the sector,” said Jim Tucker, joint administrator of First Oil Expro and restructuring partner at KPMG.
The oil-company debt reviews come at a tough time for oil explorers that aren’t brand names but take risks to open up fields in risky regions that bigger companies such as Exxon Mobil Corp. XOM 0.37 % often tap into later, such as Kurdistan in Iraq.
Investors pulled back from these companies as oil prices fell, sending share prices into the basement. That crimped their ability to raise cash by issuing new stock or selling new debt, such as corporate bonds, analysts say. The explorers’ revenues also fell, and many had to cut the value of their fields and reserves.
Some factors are working in the energy companies’ favor. Banks have an incentive not to turn the screws too tightly on oil companies, forcing them out of business and into default on loans. Several companies also have oil and gas fields that are set to begin production soon and provide a jolt of cash.
At Tullow, Mr. Springett said the company was on firm ground because a large oil field in Ghana is due to begin pumping later this year. And Cairn is developing fields in the U.K. North Sea that are due to come onstream next year, Mr. Thomson said.
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Headline crude prices for the week beginning 13 May 2019 – Brent: US$70/b; WTI: US$61/b
Headlines of the week
Midstream & Downstream
The world’s largest oil & gas companies have generally reported a mixed set of results in Q1 2019. Industry turmoil over new US sanctions on Venezuela, production woes in Canada and the ebb-and-flow between OPEC+’s supply deal and rising American production have created a shaky environment at the start of the year, with more ongoing as the oil world grapples with the removal of waivers on Iranian crude and Iran’s retaliation.
The results were particularly disappointing for ExxonMobil and Chevron, the two US supermajors. Both firms cited weak downstream performance as a drag on their financial performance, with ExxonMobil posting its first loss in its refining business since 2009. Chevron, too, reported a 65% drop in the refining and chemicals profit. Weak refining margins, particularly on gasoline, were blamed for the underperformance, exacerbating a set of weaker upstream numbers impaired by lower crude pricing even though production climbed. ExxonMobil was hit particularly hard, as its net profit fell below Chevron’s for the first time in nine years. Both supermajors did highlight growing output in the American Permian Basin as a future highlight, with ExxonMobil saying it was on track to produce 1 million barrels per day in the Permian by 2024. The Permian is also the focus of Chevron, which agreed to a US$33 billion takeover of Anadarko Petroleum (and its Permian Basin assets), only for the deal to be derailed by a rival bid from Occidental Petroleum with the backing of billionaire investor guru Warren Buffet. Chevron has now decided to opt out of the deal – a development that would put paid to Chevron’s ambitions to match or exceed ExxonMobil in shale.
Performance was better across the pond. Much better, in fact, for Royal Dutch Shell, which provided a positive end to a variable earnings season. Net profit for the Anglo-Dutch firm may have been down 2% y-o-y to US$5.3 billion, but that was still well ahead of even the highest analyst estimates of US$4.52 billion. Weaker refining margins and lower crude prices were cited as a slight drag on performance, but Shell’s acquisition of BG Group is paying dividends as strong natural gas performance contributed to the strong profits. Unlike ExxonMobil and Chevron, Shell has only dipped its toes in the Permian, preferring to maintain a strong global portfolio mixed between oil, gas and shale assets.
For the other European supermajors, BP and Total largely matched earning estimates. BP’s net profits of US$2.36 billion hit the target of analyst estimates. The addition of BHP Group’s US shale oil assets contributed to increased performance, while BP’s downstream performance was surprisingly resilient as its in-house supply and trading arm showed a strong performance – a business division that ExxonMobil lacks. France’s Total also hit the mark of expectations, with US$2.8 billion in net profit as lower crude prices offset the group’s record oil and gas output. Total’s upstream performance has been particularly notable – with start-ups in Angola, Brazil, the UK and Norway – with growth expected at 9% for the year.
All in all, the volatile environment over the first quarter of 2019 has seen some shift among the supermajors. Shell has eclipsed ExxonMobil once again – in both revenue and earnings – while Chevron’s failed bid for Anadarko won’t vault it up the rankings. Almost ten years after the Deepwater Horizon oil spill, BP is now reclaiming its place after being overtaken by Total over the past few years. With Q219 looking to be quite volatile as well, brace yourselves for an interesting earnings season.
Supermajor Financials: Q1 2019
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January, April, and May 2019 editions
In its May 2019 edition of the Short-Term Energy Outlook (STEO), EIA revised its price forecast for Brent crude oil upward, reflecting price increases in recent months, more recent data, and changing expectations of global oil markets. Several supply constraints have caused oil markets to be generally tighter and oil prices to be higher so far in 2019 than previous STEOs expected.
Members of the Organization of the Petroleum Exporting Countries (OPEC) had agreed at a December 2018 meeting to cut crude oil production in the first six months of 2019; compliance with these cuts has been more effective than EIA initially expected. In the January STEO, OPEC’s crude oil and petroleum liquids production was expected to decline by 1.0 million b/d in 2019 compared with the 2018 level, but EIA now forecasts OPEC production to decline by 1.9 million b/d in the May STEO.
Within OPEC, EIA expects Iran’s liquid fuels production and exports to also decline. On April 22, 2019, the United States issued a statement indicating that it would not reissue waivers, which previously allowed eight countries to continue importing crude oil and condensate from Iran after their waivers expired on May 2. Although EIA’s previous forecasts had assumed that the United States would not reissue waivers, the increased certainty regarding waiver policy and enforcement led to lower forecasts of Iran’s crude oil production.
Venezuela—another OPEC member—has experienced declines in production and exports as a result of recurring power outages, political instability, and U.S. sanctions. In addition to supply constraints that have already materialized in 2019, political instability in Libya may further affect global supply. Any further escalation in conflict may damage crude oil infrastructure or result in a security environment where oil fields are shut in. Either situation could reduce global supply by more than EIA currently forecasts.
In the May STEO, total OPEC crude oil and other liquids supply was estimated at 37.3 million b/d in 2018, and EIA forecasts that it will average 35.4 million b/d in 2019. EIA assumes that the December 2018 agreement among OPEC members to limit production will expire following the June 2019 OPEC meeting.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January, April, and May 2019 editions
U.S. crude oil and other liquids production is sensitive to changes in crude oil prices, taking into account a lag of several months for drilling operations to adjust. As crude oil prices have increased in recent months, so too have EIA’s domestic liquid fuels production forecasts for the remaining months of 2019.
U.S. crude oil and other liquids production, which grew by 2.2 million b/d in 2018, is forecast in EIA’s May STEO to grow by 2.0 million b/d in 2019, an increase of 310,000 b/d more than anticipated in the January STEO. In 2019, EIA expects overall U.S. crude oil and liquids production to average 19.9 million b/d, with crude oil production alone forecast to average 12.4 million b/d.
Relative to these changes in forecasted supply, EIA’s changes in forecasted demand were relatively minor. EIA expects that global oil markets will be tightest in the second and third quarters of 2019, resulting in draws in global inventories. By the fourth quarter of 2019, EIA expects that inventories will build again, and Brent crude oil prices will fall slightly.
More information about changes in STEO expectations for crude oil prices, supply, demand, and inventories is available in This Week in Petroleum.