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.
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
Source: U.S. Energy Information Administration, Monthly Refinery Report
The API gravity of crude oil input to U.S. refineries has generally increased, or gotten lighter, since 2011 because of changes in domestic production and imports. Regionally, refinery crude slates—or the mix of crude oil grades that a refinery is processing—have become lighter in the East Coast, Gulf Coast, and West Coast regions, and they have become slightly heavier in the Midwest and Rocky Mountain regions.
API gravity is measured as the inverse of the density of a petroleum liquid relative to water. The higher the API gravity, the lower the density of the petroleum liquid, so light oils have high API gravities. Crude oil with an API gravity greater than 38 degrees is generally considered light crude oil; crude oil with an API gravity of 22 degrees or below is considered heavy crude oil.
The crude slate processed in refineries situated along the Gulf Coast—the region with the most refining capacity in the United States—has had the largest increase in API gravity, increasing from an average of 30.0 degrees in 2011 to an average of 32.6 degrees in 2018. The West Coast had the heaviest crude slate in 2018 at 28.2 degrees, and the East Coast had the lightest of the three regions at 34.8 degrees.
Production of increasingly lighter crude oil in the United States has contributed to the overall lightening of the crude oil slate for U.S. refiners. The fastest-growing category of domestic production has been crude oil with an API gravity greater than 40 degrees, according to data in the U.S. Energy Information Administration’s (EIA) Monthly Crude Oil and Natural Gas Production Report.
Since 2015, when EIA began collecting crude oil production data by API gravity, light crude oil production in the Lower 48 states has grown from an annual average of 4.6 million barrels per day (b/d) to 6.4 million b/d in the first seven months of 2019.
Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production Report
When setting crude oil slates, refiners consider logistical constraints and the cost of transportation, as well as their unique refinery configuration. For example, nearly all (more than 99% in 2018) crude oil imports to the Midwest and the Rocky Mountain regions come from Canada because of geographic proximity and existing pipeline and rail infrastructure between these regions.
Crude oil imports from Canada, which consist of mostly heavy crude oil, have increased by 67% since 2011 because of increased Canadian production. Crude oil imports from Canada have accounted for a greater share of refinery inputs in the Midwest and Rocky Mountain regions, leading to heavier refinery crude slates in these regions.
By comparison, crude oil production in Texas tends to be lighter: Texas accounted for half of crude oil production above 40 degrees API in the United States in 2018. The share of domestic crude oil in the Gulf Coast refinery crude oil slate increased from 36% in 2011 to 70% in 2018. As a result, the change in the average API gravity of crude oil processed in refineries in the Gulf Coast region was the largest increase among all regions in the United States during that period.
East Coast refineries have three ways to receive crude oil shipments, depending on which are more economical: by rail from the Midwest, by coastwise-compliant (Jones Act) tankers from the Gulf Coast, or by importing. From 2011 to 2018, the share of imported crude oil in the East Coast region decreased from 95% to 81% as the share of domestic crude oil inputs increased. Conversely, the share of imported crude oil at West Coast refineries increased from 46% in 2011 to 51% in 2018.
Headline crude prices for the week beginning 7 October 2019 – Brent: US$58/b; WTI: US$52/b
Headlines of the week
In the October 2019 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts lower crude oil prices in the fourth quarter of 2019 and in 2020 despite tighter global balances. The tighter balances are largely the result of unprecedented short-lived loss of global supply following the September 14 attacks on crude oil production and processing infrastructure in Saudi Arabia. The production declines contribute to overall stock draws in the second half of 2019 with a relatively large stock draw in the third quarter. In the fourth quarter, however, EIA forecasts global supply growth will outpace global demand growth, resulting in an inventory build, offsetting some of the third quarter draws (Figure 1). EIA lowered its crude oil price forecast for the fourth quarter of 2019 by $1 per barrel (b) to $59/b, reflecting current price trends, and lowered its crude oil price forecast for 2020 by $2/b to average $60/b because of expected supply growth.
In the October STEO, EIA forecasts total global petroleum stocks in the second half of 2019 will decrease by an average of 290,000 barrels per day (b/d), compared with the September STEO forecast stock build of 250,000 b/d for the same period. EIA forecasts total world crude oil and other liquids production for the second half of 2019 to average 101.3 million b/d, down by 550,000 b/d from the September STEO. Most of the production decline is the result of lower output from Saudi Arabia, reducing the collective output of the Organization of the Petroleum Exporting Countries (OPEC) to 34.8 million b/d for the second half of 2019.
In the October STEO, EIA assumed the Abqaiq facility and Khurais oil field would produce at their pre-attack levels by the end of October. Compared with the September STEO, EIA revised OPEC spare capacity, most of which is located in Saudi Arabia, lower by an average of 200,000 b/d in the second half of 2019. Saudi Arabia's total capacity (including spare capacity) declined following the Abqaiq attack, and EIA expects Saudi Arabia will use some of its remaining spare capacity to backfill inventories and lost production through the end of 2019. Beginning in January 2020, EIA forecasts that OPEC spare capacity will return above 2.0 million b/d.
Crude oil prices increased sharply following the attacks; Brent front-month futures prices rose by nearly 15% on Monday, September 16, the first day of post-attack trading. This increase was the largest one-day percentage increase on record for Brent front-month futures prices. The increase was larger in the front months of the futures strip than in the later months, indicating the market expected the outage to be relatively short lived, and prices fell quickly after the attack (Figure 2). Saudi Arabia continued to export crude oil by drawing from inventories, increasing production in other fields, and reducing domestic refinery inputs. Abqaiq's relatively quick return to operations likely lessened the extent and duration of the price increases. Brent front-month futures prices fell to lower than pre-attack levels on October 1, settling at $59/b for the December contract and have fallen slightly since then.
The relatively quick return to pre-attack price levels likely reflects demand-side concerns and increased down-side price risk. Despite tighter forecast global petroleum markets in the second half of 2019, EIA expects that the Brent crude oil price will average $60.63/b in the second half of 2019, nearly unchanged from the $60.68/b forecast in the September STEO. EIA forecasts that global petroleum inventories will increase by nearly 550,000 b/d in the first half of 2020, which is expected to put downward pressure on crude oil prices. EIA forecasts the price of Brent crude oil to average $57.34/b during the first half of 2020. However, EIA expects the price of Brent crude oil to increase to $62.48/b in the second half of 2020 as global petroleum stock builds slow and petroleum balances are relatively tighter than during the first half of the year.
The price forecast is highly uncertain and supply or demand factors may emerge that could move prices higher or lower than EIA's current STEO forecast. Driven by revisions to global economic outlook, EIA has revised its 2019 liquid fuels demand growth outlook lower in the STEO for the last nine consecutive months and 2020 consumption has been revised down eight of the last nine months. EIA's price forecast also accounts for a higher level of petroleum supply risk in the aftermath of the attacks in Saudi Arabia.
U.S. average regular gasoline prices increase slightly, diesel prices fall
The U.S. average regular gasoline retail price rose less than 1 cent from the previous week to $2.65 per gallon on October 7, 26 cents lower than the same time last year. The West Coast price rose by nearly 10 cents to $3.64 per gallon, and gasoline prices in California continued to rise, increasing by 14 cents to $4.09 per gallon, 55% higher than the national average and 39 cents higher than the same time last year. The Midwest price increased by more than 1 cent to $2.50 per gallon, and the Rocky Mountain price increased by less than 1 cent, remaining at $2.71 per gallon. The Gulf Coast price fell by more than 4 cents to $2.28 per gallon, and the East Coast price fell by 2 cents to $2.49 per gallon.
The U.S. average diesel fuel price fell nearly 2 cents to $3.05 per gallon on October 7, 34 cents lower than a year ago. The East Coast and Gulf Coast prices each fell by more than 2 cents to $3.04 per gallon and $2.80 per gallon, respectively, the Midwest price fell by 2 cents $2.97 per gallon, the Rocky Mountain price decreased 1 cent to $3.02 per gallon, and the West Coast price decreased by less than 1 cent to $3.64 per gallon.
Propane/propylene inventories increase
U.S. propane/propylene stocks increased by 0.1 million barrels last week to 100.8 million barrels as of October 4, 2019, 11.9 million barrels (13.4%) greater than the five-year (2014-18) average inventory levels for this same time of year. Gulf Coast inventories increased by 1.0 million barrels, and Midwest inventories rose slightly, remaining virtually unchanged. East Coast inventories decreased by 0.9 million barrels, and Rocky Mountain/West Coast fell slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 4.4% of total propane/propylene inventories.
Residential Heating Fuel Price Survey Begins This Week
Beginning this week and continuing through the end of March 2020, prices for wholesale and residential heating oil and propane will be included in This Week in Petroleum and on EIA's Heating Oil and Propane Update webpage.
As of October 7, 2019, residential heating oil prices averaged nearly $2.95 per gallon, 41 cents per gallon lower than at the same time last year. The average wholesale heating oil price for the start of the 2019–20 heating season is $1.99 per gallon, over 48 cents per gallon below the October 8, 2018, price.
Residential propane prices entered the 2019–20 heating season averaging nearly $1.86 per gallon, 53 cents per gallon less than the October 8, 2018, price. Wholesale propane prices averaged more than $0.58 per gallon, 43 cents per gallon lower than the same time last year.