Brent-WTI spread disappears– for now

On Friday the benchmark crude oil traded in the central United States (West Texas Intermediate) sold for the same price as the benchmark European crude (Brent). That’s the first time that’s happened in almost three years. But I don’t expect the situation to persist.

Black: price of West Texas Intermediate, in dollars per barrel, weekly Jan 7, 2000 to Jul 19, 2013; blue: price of Brent; green: Brent minus WTI. Data source: EIA. Last entries from

Brent and WTI are very similar products, and historically sold for essentially the same price. But surging production from Canada and the central United States overwhelmed capacity to transport crude out of the hub in Cushing, Oklahoma where existing pipelines carry it. The result was that U.S. refineries on the coast paid the high world price for imported crude, lacking a cheap way to access the product landlocked in Cushing.

U.S. field production of crude oil.
Source: Early Warning.

Since 2010, infrastructure for transport and delivery of crude to U.S. refiners by rail and barge has grown tremendously. This has narrowed the Brent-WTI spread, but is not enough to eliminate it, since pipelines are an economically more efficient (and environmentally more friendly) way to transport oil.

Source: American Association of Railroads.

Source: EIA.

Pipeline infrastructure to deliver more crude oil from the central U.S. to coastal refineries is gradually coming on line. The recently reversed Seaway Pipeline has been carrying an estimated 300,000 barrels a day out of Cushing, and its operators hope to twin it with a second line upping the capacity to 850,000 barrels a day by the end of next year. The reversed Magellan Longhorn pipeline (225,000 b/d capacity) has started carrying crude directly from west Texas to Houston refineries, bypassing the glut in Cushing. Also helping relieve the glut has been the completion of improvements to BP’s refinery in Whiting, Indiana, which is now using close to 400,000 b/d of the surplus crude. All this has helped to finally draw down inventories of crude oil in the Midwest to the levels seen in December, though there’s still a long way to go.

Commercial inventories of crude oil in Midwest (PADD 2).
Source: EIA.

The Gulf Coast leg of the Keystone project, which can carry an additional 700,000 b/d from Cushing to the coast, is expected to begin operation by the end of the year. But other projects will also likely soon be bringing even more oil from Canada and the U.S. into Cushing. These include 600,000 b/d from the South Flanagan project and another 800,000 b/d that could be delivered through the proposed Canada-to- Nebraska leg of the Keystone project. The latter may never be approved, but the former simply twins an existing line within the United States. Other projects are also underway that would bring even more oil into Cushing. All of this means that the elimination of the Brent-WTI spread may prove to be a short-lived phenomenon.

Source: EIA.

In any case, although infrastructure for transporting crude within the U.S. is still inadequate, pipelines for refined products like gasoline are better, which means that refined products sell for the same price in America as elsewhere in the world. This is the reason that U.S. gasoline prices tend to track Brent more closely than WTI. A rule of thumb that’s held up pretty well is that the retail price that Americans pay for a gallon of gasoline goes up about 2.5 cents for every $1.00/barrel increase in the price of Brent.

Average retail price of U.S. gasoline (black) and price predicted on the basis of price of Brent crude oil (blue). Black: average U.S. price of retail gasoline, all formulations, in dollars per gallon, weekly Jan 10, 2000 to Jul 19, 2013 (data source: EIA).
Blue: 0.84 plus 0.025 times price of Brent, in dollars per barrel, weekly Jan 7, 2000 to Jul 19, 2013 (data source: EIA). Last entries from and

Here’s a little calculator you can use to get the predicted gasoline price plotted in blue in the graph above; just enter the current price of Brent to see the predicted gasoline price. The long-run relation says that, based on the current price of Brent at $108.07/barrel, we’d expect the average U.S. retail gasoline price to be about $3.54/gallon. That suggests that U.S. gasoline prices might soon fall by about 14 cents/gallon.

Crude Oil Price Data
Input Data Values
Price per Barrel of Brent Crude Oil

Implied average U.S. gasoline price
Calculated Results Values
Average U.S. Price per Gallon
Code created with the assistance of Political Calculations
Here's a self-updating reference to the current Brent price if you want to come back to this page to recalculate the expected U.S. gasoline price as the price of Brent changes.

And here is a self-updating plot of the average U.S. retail gasoline price so you can come back to see if I was right.

New Jersey Historical Gas Price Charts Provided by

22 thoughts on “Brent-WTI spread disappears– for now

  1. Jeffrey J. Brown

    In any case, I suspect that the days of the really big Brent-WTI spreads are over.
    The Mid-continent refiners had a great run for a couple of years–buying crude at WTI prices and basically selling product at Brent prices.
    Regarding US oil & gas production, I think that what almost everyone is missing is the significant increase in the decline rates from existing production.
    I suspect that the decline rate from existing US crude oil production is in the vicinity of 10%/year, and increasing, as an increasing share of US crude oil production comes from high decline rate tight/shale plays. At a 10%/year decline rate, in order to maintain the current US crude oil production rate for 10 years, the US would have to replace the productive equivalent of every US oil field over the next 10 years.
    Citi Research recently issued a report which put the decline rate from existing US natural gas production at about 24%/year. At a 24%/year decline rate, in order to maintain the current US natural gas production rate for four years, the US would have to replace the productive equivalent of virtually all current US natural gas production over the next four years.

  2. Jeffrey J. Brown

    A case history from the Barnett Shale Play, in Texas (MMCFPD = mmcfpd = million cubic feet per day, cfe refers to natural gas + natural gas liquids converted to gas equivalent):
    A couple of items follow, emphasis added, from 2007 regarding Chesapeake’s DFW Airport Lease, in the Barnett Shale Play.
    In 2007, Chesapeake estimated that late 2011 production from the lease would be up to 250 MMCFPD, and they estimated that production would continue for at least 50 years. In 2007, they also said that the lease ” likely contains one of the thickest and best-developed reservoir facies anywhere in the play.”
    Actual late 2011 production from the lease was only about 35 MMCFPD. Of course, the sharp decline in gas prices had an impact on drilling, but it’s interesting to take a look at how the wells that Chesapeake drilled and completed on the lease in 2007 have done over the past few years. (That info is found below.)
    Chesapeake Announces First Natural Gas Production from Dallas/Fort Worth International Airport Lease with Initial Sales of 30 mmcfe Per Day from First 11 Barnett Wells (October, 2007)
    (Search for above title for link)

    OKLAHOMA CITY–(BUSINESS WIRE)–Oct. 30, 2007–Chesapeake Energy Corporation (NYSE:CHK) today announced that it has recently initiated production of approximately 30 million cubic feet of natural gas equivalent (mmcfe) from the first 11 wells on its 18,000-acre Dallas/Fort Worth (DFW) International Airport lease. Acquired approximately one year ago for $185 million, the airport lease represents a significant value creation opportunity for Chesapeake, its minority- and women-owned business enterprise (M/WBE) partners and DFW International Airport. Based on the results of the company’s proprietary 3-D seismic analysis acquired earlier this year and the drilling, completion and production results to date, the company plans to drill approximately 300 – 325 wells on the airport lease.
    Assuming an estimated average recovery of approximately 2.5 – 3.0 billion cubic feet of natural gas equivalent (bcfe) gross reserves per well, the company believes that up to one trillion cubic feet of natural gas equivalent (tcfe) reserves can be produced from under the airport at an all-in finding and development cost of approximately $2.00 per thousand cubic feet of natural gas equivalent (mcfe).
    Since commencing 3-D seismic operations in December 2006 and drilling operations in May 2007, Chesapeake has employed five drilling rigs on a continuous basis at the airport and anticipates maintaining that level of activity through 2011, at which time the company should have completed drilling its planned 300 – 325 wells. To date, Chesapeake has initiated drilling activities on 33 wells, has started completion activities on 18 wells and is selling natural gas from 11 wells. Chesapeake hopes to reach a peak production level from the airport lease of approximately 250 mmcfe per day by year-end 2011 and expects production to continue for at least the next 50 years.

    (End Excerpt)
    And here is an item from the July, 2007 American Oil & Gas Reporter:
    Chesapeake Images Barnett Shale Beneath DFW Airport
    (Search for above title for link)

    But for Chesapeake Energy Corporation, the airport itself holds the ticket to expanding the company’s presence in the red-hot play, says Larry Lunardi, Chesapeake’s vice president of geophysics. “The Barnett has been arguably the fastest growing gas play in the world, and we are aware of precious few opportunities to lease so much contiguous acreage,” relates Lunardi, noting that the chain link fences surrounding the airport’s perimeter encircle 18,076 acres untouched by a drill bit. “The airport not only represents one of the single largest remaining Barnett Shale lease opportunities, but this acreage likely contains one of the thickest and best-developed reservoir facies anywhere in the play. That is the biggest reason we are so excited about the DFW project.”

    (End Excerpt)
    Update on Wells Completed in 2007
    The DFW Airport Lease had production of 52 MMCFPD in January, 2008, which would presumably be attributable to the 21 wells drilled and completed in 2007. The wells still producing from the 2007 group produced 2.6 MMCFPD in April, 2013 (with 10 of the 21 wells already having been plugged & abandoned).
    This is about a 95% simple percentage decline in a little over five years, or an exponential decline rate of about 60%/year in monthly production (2007 wells only).
    Total cumulative production from the 21 wells completed in 2007 appears to be 16.5 BCF, or about 0.8 BCF per well, after a 95% decline in production from January, 2008. Note that Art Berman puts the average EUR per well on the DFW Airport Lease at about 0.9 BCF per well.
    It does seem that Chesapeake’s proclamation that the DFW Airport gas wells would produce gas for at least 50 years is a “little” on the optimistic side, especially since about half of the wells that they publicized in 2007 have already been plugged and abandoned. Odd that they did not issue a press release about that.
    Here’s a thought experiment. Assume that the 21 wells they put on line on the DFW Airport Lease in 2007 were the total gas supply for the country. In a little over five years, our total gas supply would have dropped by 95%. This is the revolution that will power us to a virtually infinite rate of increase in oil and gas production?

  3. Steven Kopits

    Not so sure WTI will again diverge so markedly from Brent.
    Canada’s oil sands production is being challenged by high costs, and Canadian oil production is actually down from recent highs (some weather-related).
    Using technical analysis, the Bakken looks like it has about another 150 kpbd until it peaks in late 2016. So growth will be decreasing rapidly in that play.
    The Eagle Ford and Permian are much nearer to Houston and have substantial existing infrastructure.
    I’m prepared to be wrong about this, but I would expect WTI to track Brent more closely in the future.

  4. Steven Kopits

    Here’s something to consider:
    – Europe is in recession
    – Japan is relatively weak
    – US GDP growth looks to be 1.0% in Q2
    – China is wobbly, and growth there may be only 3-4%
    And Brent is at $108.

  5. Vangel

    The biggest issues that Americans need to examine is the profitability of shale and the decline rates of existing fields. It should be clear to everyone by now that shale gas was a total disaster for producers. Billions have been written off and many more billions will follow. The picture for shale oil may not be much better because the SEC filings are showing massive explosions of debt and continued negative cash flows even for companies that have been producing shale oil for a while. The ND data also shows us the true state of the industry. Even though we saw around $17 billion in drilling to increase the number of horizontal wells by around 43% the average production rate per well FELL by 10% to 130 bpd. To understand what this means we have to keep in mind that shale wells produce about half of their oil in the first three years and have the greatest production rate in the first year. While we could see the average rate go back up to around 140 that is nowhere near what is required to show that shale oil is profitable.
    I find it strange that so many intelligent analysts forget that one of the keys to the natural resource sector is turning resources into reserves. To do that there are several steps that must be taken and reported. Sadly, the rules that apply to copper, gold, or conventional oil exploration do not apply to shale exploration and development. Even though shale formations are not very uniform companies are allowed to make certain assumptions about how much wells in a given area will produce without having to prove it by having a number of wells that can verify those assumptions. It is my guess that some time in the next year or two reality will begin to intervene and we will see several companies having to write down the value of the assets on their balance sheets. At some point the lenders will finally figure out that they will not get paid and they will try to get rid of their problems by securitizing energy loans and selling them off to the usual patsies or will demand another bailout from the government. At that point all the analysts who were hyping shale without looking at the details clearly shown in the filings will be suggesting that the people who ‘misled them’ should be sent to jail.

  6. Darren

    Steven Kopits,
    – US GDP growth looks to be 1.0% in Q2
    – China is wobbly, and growth there may be only 3-4%

    I am amazed that people still make the error of considering ‘real’ GDP, rather than nominal, when making such estimations.
    Oil demand (as well as corporate earnings, revenue, etc.) is governed by Nominal GDP, not ‘real’ GDP, which is a metric that is totally useless on a quarterly basis (it is only useful in longer-term calculations).

  7. Jeffrey J. Brown

    Regarding annual Brent crude oil prices, we have so far seen a cyclical pattern of higher annual highs and higher annual lows, since 1997. Here are the three year over year declines in annual Brent crude oil prices since 1997, along with the rates of change since the 1998 low:
    1998: $13
    2001: $25 (+22%/year)
    2009: $62 (+11%/year)
    If the 2013 annual Brent crude oil price declines to the current price of $108, this would be a +14%/year rate of change, relative to the $62 price in 2009, which would be between the 1998 to 2001 and 2001 to 2009 rates of change.

  8. JDH

    Jeffrey J. Brown at July 22, 2013 05:31 AM and Steven Kopits at July 22, 2013 06:05 AM: I agree, and should have been more clear. The Brent-WTI spread is not going back to $20/barrel. But I would not be surprised to see the spread back to $5/barrel by the end of next year.

    Bruce Hall: I would say it is overall good news in the sense that we are finding more efficient ways to get the product to where it is most valuable. But as with any change, there are winners and losers. Winners include North American oil producers, coastal refiners, railroads, and consumers. Losers are Midwest refiners.

  9. Johannes

    Solid work, thanks, give you a plus. WTI will track Brent more closely in the future, yes. The future is bright.

  10. Darren

    But I would not be surprised to see the spread back to $5/barrel by the end of next year.
    Well, that is pretty long-term. 18 months.
    Since the spread compressed from $6 to $0 in just 3 weeks, the reverse can also happen that quickly. This could be useful from a trading point of view.
    The collapse from $20 to $6 was more fundamental. The $6 to $0 and back to $6 will be faster.

  11. James

    We are looking at effectively perfect substitutes which have been historically priced a varying differentials to one another; why is that? is still a rational question although thinking that the answer will not continue to change over time is highly irrational.
    Dating back to the 90’s, WTI futures for prompt delivery carried an average premium of $3/bbl over the 1st nearby Brent contract. When crude was trading at $25/bbl, this was financially a 12% premium to the international marker for light sweet crude. At $15/bbl and the same spread in dollar terms, this was a higher premium in % terms; at $30/bbl it was the opposite. The reason for WTI’s prevailing premium is financial in nature because we are dealing with financial contracts that drive the physical market(see exchange of future for physical). The prolonged reversal of this spread is also the result of financial conditions which in turn drives physical market conditions in line.
    We have to accept the Brent premium as no less reasonable than a WTI premium; therefore when nearby Brent futures were priced at $110/bbl and traded at a $15/bbl differential to the prompt WTI contract, the 13.5% premium was financially in line by historical measures. In reality, the headline price that is obsessed over is largely irrelevant on its own. Oil backed-secured funding agreements are the most important transactions in the physical arbitrage market. Expectations of changing short term financial conditions have likely impacted the WTI and Brent forward curves through these transactions.

  12. Ricardo

    Steven and Jeffery,
    What is your assessment of Australia’s Arckaringa Basin shale oil discovery?

  13. Steven Kopits

    Art Berman took a lot of arrows for his call on the Barnett. He lost is column at World Oil and was excoriated by one of the investment banks.
    And, of course, Art was right.

  14. Jeffrey J. Brown

    Regarding the Arckaringa Basin, I think that a blogger named “GarryP” had a very good analysis (emphasis added):

    It’s Linc Energy, the story from about 6 months ago, recycled for another round of pump’n’dump.
    1. Nobody is quite sure what it is. The reports they reference are an exercise in obscuration and weasel words – but it does mention the key word ‘kerogen’ once or twice (eg “are rich in oil and gas-prone kerogen”). That’s kind of a tell-tale, and a death-knell. For those who don’t know, kerogen is NOT oil, it’s a precursor (kind of like as peat is to coal) that needs to be cooked under pressure to create oil. It’s all over the place and NOBODY has a workable way to turn it into real oil – big oil companies like Shell have been trying for decades. One of the major problems, besides you have to put a metric sh*t load of energy IN to convert it, is that the spoil produced afterwards is bigger than what you dig out (eg it don’t fit back into the hole).
    In other words, if it’s kerogen, as seems likely, it’s worthless.
    2. If it were tight oil (aka shale oil) then it still doesn’t mean it’s viable. You need a lot of factors to align to make a play where it is viable to drill the thousands of wells necessary to recover it via fracking (there’s that dreaded word). In particular you need the structure to be criss crossed by fault lines, so that your fracking can intersect these and recover oil from a much large volume. Even then, you are looking at 10% recovery. If it’s not, you’d be looking at a cost per barrel that means it would forever stay in the ground.
    3. Oil production at reasonable costs is all about finding concentrations of oil – not oil bearing rocks. If you don’t have a way of it getting concentrated somehow, you generally don’t have a play. Drilling just one well costs millions, and you have to make that back and more before you can even think about it.
    Best guess is that the volumes they are talking about is mainly kerogen, with possibly a few areas where it might have been cooked enough to turn it into a bit of oil – tight shale oil. They won’t know if they can actually either find this oil, or produce it, till they drill some wells. They are pushing the story, and the numbers, to try to entice some shmuck into funding it – but frankly, after 6 months, if they don’t already have investors lined up and clamouring then they probably don’t have anything tasty.

  15. Jeffrey J. Brown

    Professor Hamilton and Steven Kopits,
    In regard to our mutual acquaintance Ed Morse, I thought you might find the following interesting. An excerpt from an email I received (emphasis added):

    To the DC folks, the second part of the Bipartisan Policy Center’s energy series is this Thursday. This one focuses on “U.S. Shale Gas Boom: Implications for the U.S. Economy, Trade, and Geopolitics”
    You may remember that I went to the first one in June, “The Geopolitical Impacts of the U.S. Tight Oil Boom: Implications for OPEC and the U.S. Strategic Posture”
    Videos for that one are available online here:
    In the first panel discussion, I remember being surprised to hear Citibank’s Ed Morse spending time explaining his three possible risks to the tight oil boom: steep decline rates, environmental disasters, and price risks.

  16. Jeffrey J. Brown

    In regard to Ed Morse’s somewhat belated discovery that tight/shale plays have high decline rates, here is a link to and an excerpt from a March, 2012 WSJ OpEd piece by Mr. Morse:
    Move Over, OPEC—Here We Come (March, 2012)
    In energy, North America is becoming the new Middle East. The only thing that can stop it is domestic politics.

    The United States has become the fastest-growing oil and gas producer in the world, and it is likely to remain so for the rest of this decade and into the 2020s. Add to this output the steadily growing Canadian production and a likely reversal of Mexico’s recent production decline, and theoretically total oil production from the three countries could rise by 11.2 million barrels per day by 2020, or to 26.6 million barrels per day from around 15.4 million per day at the end of 2011.
    Whether the increase results in the U.S. reducing its imports or whether our net exports grow doesn’t matter much to world balances. Either way, North America is becoming the new Middle East. The only thing that can stop this is politics—environmentalists getting the upper hand over supply in the U.S., for instance; or First Nations impeding pipeline expansion in Canada; or Mexican production continuing to trip over the Mexican Constitution, impeding foreign investment or technology transfers—in North America itself.
    On top of this, the U.S. and Canada could see natural gas output rise by 22 billion cubic feet per day by 2020, with 14 billion of it coming from the Lower 48 states, four billion from Alaska and four billion from Canada. That’s an increase of one-third, catapulting this continent into the ranks of significant exporters of liquefied natural gas.

  17. Steven Kopits

    Ed was always an optimist on supply.
    Our numbers right now suggest the shales oils have another 1.4 mbpd in them to peaking, sometime in, say, mid-2016 or so.
    I am penciled in to speak at the CSIS in DC on the 7th on “Reaching the Limits of America’s Energy Boom”.
    We’ll see if the date solidifies, but I’ll add my two cents’ worth if it does.

  18. Jeffrey J. Brown

    In my opinion, Art Berman is to shale play economics as Meredith Whitney was to the financial crisis. In both cases, they were heavily criticized, but subsequent events and data have largely supported their warnings.
    And of course, Meredith has been warning, for a while, about local and state government finances. She was just on CNBC warning that Detroit’s bankruptcy is just the beginning. In the interview, she differentiates between regions doing relatively well, e.g., the oil & gas producing areas, and the areas not doing well, e.g. Detroit.
    My 2¢ worth, using my “Export Land Model.”
    The GELM (Government Export Land Model)
    Let’s think of local and state (provincial), and for that matter, national governments as being similar to oil exporting countries, in that they consume a percentage of tax revenues and net debt infusions, in order to pay current benefits to employees and operating expenses and to pay current and future retirement/health benefits.
    And let’s just really focus on current and future retirement benefits.
    As Michael Lewis noted in his recent book, “Boomerang,” a lot of local governments, especially in California, are on track to consist of little more than a small staff that collects taxes and forwards virtually all tax revenue to retirees. And of course, most public pension systems are assuming a (highly unrealistic) estimate of 7% to 8% on future annual returns. Of course, the lower the actual investment return, the larger the unfunded pension obligation.
    In any case, if we assume flat to declining tax revenue, combined with rising retirement obligations (especially as investment returns continue to disappoint), it seems to me that the net result would be an accelerating rate of decline in services provided to the taxpayers, perhaps even as governments try (probably) unsuccessfully to materially raise tax revenue, by raising tax rates.
    From an Amazon review of “Boomerang”

    Quoting Lewis quote UCLA neuroscientist Peter Whybrow in the book’s last chapter (on California’s financial problems, not European countries), Lewis writes, “‘Human beings are wandering around with brains that are fabulously limited. We’ve got the core of the average lizard.’ Wrapped around this reptilian core is a mammalian layer (associated with maternal concern and social interaction), and around that is wrapped a third layer, which enables feats of memory and the capacity for abstract thought. ‘The only problem is our passions are still driven by the lizard core.’ Even a person on a diet who sensibly avoids coming face-to-face with a piece of chocolate cake will find it hard to control himself if the chocolate cake somehow finds him. Every pastry chef in America understands this, and now nueroscience does, too. ‘In that moment the value of eating the chocolate cake exceeds the value of the diet. We cannot think down the road when we are faced with the chocolate cake.’ … Everywhere you turn you see Americans sacrifice their long-term interests for a short-term reward.”

  19. valuethinker

    The pieces of the puzzle are in place for a steep fall in oil prices in the next 18 months:
    – rising US production
    – improving fuel economy, and sluggish economic growth/ stagnation in developed countries (especially Europe, USA to a lesser extent)
    – falling demand growth due to economic slowdowns in emerging markets (China, etc.)
    – reduction of oil price subsidies amongst some major consumers (India, Egypt etc.)
    – continued development of Iraqi oil reserves
    – existing frontier oil E&P activity coming into production (Africa etc.)
    – difficult the Saudis have in reducing production given their budgetary targets
    – substitution at the margin by natural gas for electricity (small, but potentially larger in some emerging markets), transport etc.
    We could see $60/bl oil easily. At which point the high cost producers, like Canadian tar sands, are in trouble. The Saudis may not be able to cut production that quickly and a relatively small oversupply could trigger a big price fall (probably as little as 1-2m b/d oversupply).
    Note there are increasing issues re calculation of Brent Crude price due to falling production. And there are potentially looming scandals re market manipulation of key contract prices as per LIBOR and British natural gas prices.

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