Worst Case Scenario

Jim Brown
 
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If you are an oil producer, you are facing a worst-case scenario today. Crude oil has declined to $35 and the outlook is worse than it has been in months. If you are bleeding cash at $40, you are not going to like the picture at $30.

Crude prices declined -12% last week and analysts are starting to talk about numbers below $30 a barrel. Conoco and Chevron both slashed their capex spending targets for 2016 and said they were prepared to cut even more if prices failed to rebound.

Conoco cut capex to less than half of 2014 levels and 25% below 2015 levels as they push for cash flow neutral in 2017. That means they are trying to cut costs below cash flow to keep from burning cash while they wait for prices to recover.

The big companies with dozens of projects and hundreds of producing reserves around the world can do that. Some of their legacy onshore wells have very low costs of production. The drilling costs were recovered years or even decades ago and nearly everything they sell from these wells today is total profit.

The new kids on the block are in trouble. The companies that exploded on the scene when shale fracking took off ten years ago do not have all that legacy production. A shale well is 75-85% depleted by the end of the third year. It may continue to produce at a trickle for years to come but at some point the cost of upkeep becomes more than the value of the oil.

Conoco, Chevron and Exxon could not drill another well and still be producing millions of barrels of oil 10 years from now. If Continental Resources or Whiting Petroleum stopped drilling wells they would be bankrupt three years from now or less. Their production stream requires constantly drilling new wells to offset the steep decline rates of the existing wells.

Today they are looking at the worst case scenario. With oil at $35 and probably going to $30 they cannot afford to drill new wells. You cannot spend $8 million to drill a well that will only produce $4 million in oil at current prices. The $8 million is paid up front and that $4 million comes in over the next three years. The metrics no longer work.

This is why the number of active rigs crashed a whopping -28 last week. Oil rigs declined -21. Only the big guys like COP, CVX, XOM, EOG, PXD, APC and OXY have enough money to drill wells and then wait until prices rise to complete them.

That means the smaller E&P companies are facing a choice. Spend their remaining cash drilling new holes that will not be profitable or send everybody home and go into cash hoard mode and hope that prices rebound before they run out of cash a year or two from now.

From the drop in active rigs it appears everyone is going into hoard mode. If they can afford it they need to throttle back on the active wells to preserve their production until prices rise. Slowing production will help raise prices eventually. Unfortunately that is like telling a 300-pound man you are putting him on a 1,500 calorie per day diet. He will survive but he will be miserable every day for the next two years.

There is another challenge facing the shale drillers. For the last year they have been drilling wells and capping them rather than completing them. This allowed them to work through their inventory of drilling locations but reduced expenses by about 50% because they were not fracked and put on production. At one point, there were more than 4,000 capped wells. I do not know how many there are today but I suspect that number has risen. One analyst did a lengthy analysis and said there was about 350,000 bpd of production and maybe as much as 500,000 bpd that could be activated by completing these wells. This was actually a good plan because it allowed them to keep working without adding to the current glut in production.

If oil prices were to rise they could spend their remaining cash completing these wells. Production would jump and cash flows would improve. However, with OPEC producing at record levels and global inventories still rising it could be some time before prices recover.

As a small U.S. producer you have to plan your cash flow today to keep the company alive until the end of 2017. With prices expected to rise in late 2016 and throughout 2017 we could be back in the $75-$85 per barrel range or higher by the end of 2017.


The Chevron CEO said last week there are numerous projects at Chevron and others that were funded in 2013-2014 before prices fell. Those projects are in development and will not come online until 2017-2018. With companies slashing budgets and postponing new projects there will be a shortage of oil in 2018 and beyond that will push prices significantly higher. That is good news for the shale sector because they can react faster to rising prices in 2017 and that production will fill the large project gap in 2018.

The IEA said last week the global supply glut would persist until at least late 2016 because demand was slowing and OPEC was showing "renewed determination" to maximize output. The IEA expects global inventories to rise by 300 million barrels in 2016 or about 10% of the current record levels at 3.0 billion. That is about half the pace of 2015 as non-OPEC supply declines. Non-OPEC production is expected to decline -600,000 bpd in 2016 with U.S. production falling -415,000 bpd according to the IEA. Global demand growth is expected to slow to 1.2 mbpd in 2016, down from a five-year peak at +1.8 mbpd in 2015. OPEC production rose to 31.73 mbpd in November.

Energy investors should be patient. Oil prices still have further to fall.

Active Rigs

Active drilling rigs declined -28 to 709 for the week ended on Friday and that is another 10 year low. Oil rigs fell -21 for the week to 524. Active gas rigs fell -7 to 185. Active rigs have now declined -1,222 since the high of 1,931 in September 2014. Active offshore rigs were down -2 to 23.


Oil Inventories

Crude inventories fell unexpectedly by -3.6 million barrels to 485.9 million. This has to be a bad number. If you look at the refiner inputs in the graphic below they have not fluctuated more than a few thousand barrels a day for the last month. Refiner demand actually declined -150,000 bpd last week. How did inventories fall that much if demand declined, refinery utilization fell -1.4% and imports rose +277,000 bpd?

Refinery utilization declined from 94.5% to 93.1%. That is up from the low of 86.0% on October 9th.

U.S. production fell -38,000 from 9.202 to 9.164 mbpd. The prior week was a ten-week high!

Cushing inventories rose from 59.0 million to 59.4 million and nearing a record high.

Gasoline inventories rose +0.8 million barrels to 217.7 million as refiners accelerated production of winter blended fuels.

Distillate inventories rose 5.0 million barrels to 149.4 million and a 12 week high.

In the graphic below green represents a recent high and yellow a recent low. The blue-green represents a record high.


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