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It’s not the price of oil but the cost of oil that divides the good oil stocks from the bad

posted on December 1, 2009 at 8:30 am
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I’d never say “Forget about the price of oil” when you’re thinking about buying oil or natural gas stocks. The price of oil is the tide that lifts all boats—or leaves them stuck in the muck.

But increasingly the difference between a “good” oil and natural gas stock and a “bad” oil stock isn’t the price of oil or even how much oil or gas the company has on paper or in the ground waiting for production.

The “decider” these days is cost—the amount of capital the company has to spend to explore, discover, and develop a barrel of oil, and the percentage of revenue that goes to the costs that the industry divides into categories such as finding and development, and lifting costs.

Costs have become so critical that one oil and natural gas producer Devon Energy (DVN) recently announced that it would sell off its very promising Gulf of Mexico and international oil reserves in order to concentrate on expanding its onshore natural gas production from the United States.

The vast majority of Wall Street analysts cheered the move even though natural gas seems stuck below $5 per million British Thermal Units (BTUs). And doesn’t look likely to go higher any time soon. The International Energy Agency recently projected a global natural gas glut that would persist through 2015.

On November 23, the December contract for natural gas closed at $4.45 per million BTUs. At that price many and perhaps most natural gas producers aren’t breaking even—a back of the envelope calculation says it requires a commodity market price of at least $5.25 per million BTUs to break even.

So why would Devon Energy, with a reputation as one of the sharpest pencils in the box, decide to focus on a depressed natural gas market with dismal long-term prospects and in which almost no one is making money? And why would Wall Street cheer?


If you understand the Devon Energy move, you’ll understand what is driving oil and gas company cash flows and profits these days, and how to tell a promising oil and gas stock from an also ran. After I’ve sketched out the logic of costs for you, I’ll run through how a few of the big international oil companies stack up on these measures.

Here’s what Devon Energy announced it was going to do.

The company plans to sell its Gulf of Mexico off-shore assets. These consist of about 1.5 million acres. Most (87%) undeveloped, it’s true. But Devon’s acreage includes some of the most promising deepwater discoveries in the Gulf of Mexico over the last six of seven years. The company has one of the largest deepwater inventories in the Gulf, and Devon Energy and its partners have done enough exploratory drilling to project the existence of sizeable recoverable reserves. Chevron (CVX), one of Devon’s partners projects that the St. Malo and Jack drilling blocks, for example, hold 500 million barrels of recoverable reserves.

The company is also selling off 9 million acres, again mostly undeveloped, in Azerbaijan, Russia, Brazil, and China.

What’s the matter with these assets? They’ll cost a whole lot to explore fully and then develop. Especially in comparison to their contribution to the company’s overall production.

The Gulf of Mexico and international assets combined equal just 7% of the company’s proved reserves of 2.8 billion barrels of oil equivalent. In 2009, they’ll contribute just 11% to the company’s estimated 248 million barrels of production.

And yet the company’s capital budget shows that the Gulf of Mexico and international assets will eat 29%, or $1.2 billion, of the company’s $4.1 billion annual capital spending.

The cost picture for these assets gets even worse if you look at how long it takes for production from these assets to pay back that capital investment. Investments in developing new deepwater or overseas fields can take five years before they generate significant cash flow. That means that Devon would have to go out into the capital markets to raise cash to invest in developing these assets, and then pay interest for five or more years waiting for cash flow from these fields to come in the door.

None of this would matter a whole lot if Devon Energy didn’t have an investment opportunity that required less investment, that took less time to payback, and that, because of its quick payback, could largely be funded from internal cash flow.

I’m talking about the company’s onshore natural gas reserves in the Barnett Shale region of Texas, the Haynesville Shale region of East Texas and North Louisiana, the Cana and Arkoma Woodford Shale regions of Oklahoma, and the Horn River Ootla Shale region of British Columbia. (In addition the company is a significant player in Alberta’s oil sands at its Jackfish project.)

Let’s take a closer look at the Barnett Shale region, one of the largest onshore gas fields in the United States. Devon already produces about 1 billion cubic feet of natural gas a day from its Barnett Shale properties. That’s about a quarter of the total production by all companies from this field.

But Devon could get more out of its Barnett Shale properties. The company has drilled 3,000 wells in the Barnett region since 2002 for a total of 3,500. That has taken production from 200 million cubic feet of natural gas a day from the current 1 billion cubic feet a day. But the company says it has a reserve of at least 7,500 proved drill sites that it hasn’t yet tapped.

And Devon may have a pressing need to drill those new wells as quickly as it can—if critics are right about the relatively short life span of a natural gas well in an shale formation such as Barnett. Many companies seem to be projecting 40-year lives for their wells but data analyzed by industry consultant Arthur Berman and presented at the 2009 International Peak Oil Conference from 2007 production in the Barnett shale region  comes up with an average well life of just 7.5 years and a “common” life of as little as four years. (I’ll have more on this in tomorrow’s post “Is natural gas from shale the solution or problem?”)

I frankly don’t know which side is right on the average life of a well. (Although I do know that the literature says that horizontal drilling (instead of drilling a vertical hole) extends the life of a producing well. It is also much more expensive. The figure I’ve seen suggests four to five times as expensive.)

But I do know the producing natural gas from a proven reservoir in shale on land in the United States is hugely less expensive than finding and developing a well in the deep waters of the Gulf of Mexico or in Azerbaijan.

Deutsche Bank has calculated exactly how much less expensive. Finding and development costs for the onshore North American wells are roughly $6.86 a barrel of oil equivalent. Working backward from the Deutsche Bank figure for onshore North America and the Deutsche Bank estimate for company-wide finding and development costs, I get an estimate of a finding and development cost of $31.13 a barrel for the assets that Devon has announced it wants to sell.

Before you toss that $31.13 a barrel figure out a ludicrously high—especially given the $6.86 a barrel of oil equivalent finding and development costs for the onshore North American assets, take a look at the finding and development costs for some of the international major oil companies.

Finding and development costs at ExxonMobil (XOM) were $13.19 a barrel of oil equivalent in 2008, according to Deutsche Bank. At BP $12.97. At Chevron $13.99. At Royal Dutch Shell (RDS) $13.04.

Those figures are representative of a big group of companies with relatively modest finding and development costs.

But there’s an equally large group with finding and development costs above $20 per barrel of oil equivalent. Sometimes far above $20.

Marathon (MRO) had a finding and development cost of $22.87 in 2008, according to Deutsche Bank. Occidental Petroleum (OXY) comes in at $35.47. ConocoPhillips (COP) $55.1. And Petrobras (PBR) at $58.04.

These figures, like the $31.13 for Devon’s deepwater and international assets make sense. When you have to drill really deep in very hostile climates and geologies that make accurately predicting where oil and gas reserves are, then your costs of finding and developing oil go through the roof.

You have to be careful interpreting finding and development costs when a company is spending big now on future production. Otherwise I’d never have added Statoil to Jubak’s Picks. In 2008 the company had finding and development costs of $49.57 a barrel of oil equivalent as the company ramped up spending on future production. The company’s finding and development cost in the 2004-2007 averaged just slightly below $17.

And finding and development costs aren’t the only costs that count. There’s also lifting cost, which includes all production costs including taxes and royalties. That cost for Statoil was a low $7.11 per barrel of oil equivalent. ExxonMobil, one of the most efficient oil companies among the majors, has a lifting cost, according to Deutsche Bank, of $10.87 a barrel. Occidental Petroleum comes in at $14.82. ConocoPhillips at $19.26. And Petrobras at $22.02. (For more on my buy of Statoil, see my post http://jubakpicks.com/2009/09/23/buy-statoil-hydro-sto/ )

From these numbers you can see how big a transformation Devon Energy’s asset sale will produce. From a company with a combined finding and development cost of $9.53 per barrel of oil equivalent—already low—Devon will move to a company with a finding and development cost of an extraordinarily low $6.86. And it will accomplish that by shedding assets with a finding and development cost of $31.13 a barrel of oil equivalent.

Lowering costs like this means that Devon won’t be so dependent on oil near $80 a barrel (as the company assumes in recent projections) or natural gas prices rallying and then rallying some more. It won’t have to raise capital—and pay interest—on the money it needs to develop its deepwater and onshore wells but will be able to fund drilling from internal cash flow—and to pay down debt with the proceeds from its asset sales.


Looking at costs—and therefore profits and the dependency of profits on oil prices that are higher than today—you’ll come away with an appreciation of low cost—both finding and development and lifting—companies like ExxonMobil and Chevron, among the majors. And by looking at costs you’ll also come away with an appreciation for the potential upside as well as the risk in development plays such as Statoil and Petrobras.


Full disclosure: I own shares of Devon Energy, Petrobras, and Statoil in my personal accounts.

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  • mathruchandnani on 1 December 2009

    can you comment on effect of low gas prices on ETP?

  • Jim Jubak on 1 December 2009

    As time goes by and more and more gas is in storage at as prices stay low, it’s not good for ETP. The company has built pipelines in a specific geography assuming that gbas wouild flow from here to there. Increased imports of liquefied natural gas mean that supply isn’t following the patterns that ETP assumed in its decisions about where to build. I’ll take a deeper look at this in a future post.

  • viwi on 1 December 2009

    Wow! Very insightful analysis, Jim. I now suspect that you really did not have any Thanksgiving break to make sure that this report reaches us on time.

  • FrozenFoot on 1 December 2009

    in summary… we’ll never see $20/barrel oil again… oops, never say never… and seems to be a case for XOM ??

  • ifxeyes on 2 December 2009

    Devon just broke ground on Oct. 7, ’09, on their new $750 million, 50 story tower in downtown Oklahoma City, which will be their new headquarters….I thought when I read of them selling properties, that might have something to do with their decision…maybe not.

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