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Think you know how oil prices work?

Think you know how oil prices work? thumbnail

Since Harold Hotelling developed his classic model of exhaustible resource extraction in 1931, economists have modeled the optimal extraction of a fixed stock of an exhaustible resource under the assumption that resource owners can reallocate extraction across different periods without constraint. In “Hotelling Under Pressure” (NBER Working Paper No. 20280), Soren T. Anderson, Ryan Kellogg and Stephen W. Salant argue that observed patterns of oil production and prices cannot be replicated using the Hotelling model or existing modifications.

Instead, the authors develop a model in which the decision to drill a well in a new area is unconstrained, and reacts sharply to price changes, while the subsequent maximum pace of extraction is constrained by pressure inside the well. A drilling investment problem in which the maximal flow of oil is constrained at the well level provides a better fit for the actual cost structure of the oil industry.

Using data from Texas over 1990-2007, the authors find that the rate of production from existing wells is initially high but declines rapidly, and does not respond to shocks in spot or expected future oil prices. This behavior is inconsistent with most extraction models. But it can be explained by the fact that the pace of extraction is dictated by the pressure level of the well. When a well is newly drilled, the pressure in the underground oil reservoir is high and allows for rapid production. Over time, pressure declines toward zero as the reserves are depleted. Firms do respond to oil prices, but they do so by adjusting at the extensive margin: the drilling of new oil wells.

Therefore, the authors present oil extraction as a drilling problem in which firms maximize discounted wealth by choosing when to drill their wells, but the maximum flow from these wells is constrained by pressure. The model explains that extraction at the flow constraint can be optimal even in episodes like 1998-99 when spot prices were very low and oil futures markets implied that prices were expected to rise faster than the interest rate.

A well owner who attempts to arbitrage such prices by producing below the constraint cannot recover all the deferred production at the instant prices reach their maximum in present value because production is limited by pressure levels. Instead, deferred production can only be recovered gradually over the lifetime of the well, which may include periods when the discounted oil price is lower than the current price.

Consequently, aggregate production is price inelastic. It will evolve gradually over time, following changes in the drilling rate, and will only respond to shocks with a significant lag.

The model’s equilibrium dynamics also replicate other salient features of the crude oil extraction industry. Drilling activity and rental rates on drilling rigs strongly co-vary with oil prices. Production in newly developed oil-producing regions starts low but then peaks and eventually declines as extraction slows as the number of untapped wells diminishes. Positive global demand shocks lead to an immediate increase in oil prices, drilling activity, and rig rental prices; and oil prices may subsequently be expected to fall if the increased rate of drilling causes production to increase.

Claire Brunel, National Bureau of Economic Research

PBS NewsHour    

15 Comments on "Think you know how oil prices work?"

  1. bobinget on Wed, 31st Dec 2014 6:40 am 

    Recognize, “Hotelling Under Pressure”
    is a double entendre.
    “data from Texas over 1990-2007”

    Sticking with the “pressure” theme, we are not guessing, drilling tech changed dramatically in that 17 year period. In following years, technology once again, doubles. The period from 2007 to present day realized technology changes nothing short of world fracturing.

    I’m beting this coming decade will bring, blessings
    and curses, a doubling again for “exhaustible resource extraction”.

  2. rockman on Wed, 31st Dec 2014 7:54 am 

    “When a well is newly drilled, the pressure in the underground oil reservoir is high and allows for rapid production. Over time, pressure declines toward zero as the reserves are depleted.” Completely untrue for a large percentage of oil reservoirs including some of the giant fields. He is describing a pressure depletion drive which does occur. Mexico’s Cantarell Field is a good example of such a major reservoir. But even in this case the author is not correct in characterizing its production profile. Though it has a pressure depletion drive and would have responded as described but for many years they have been injecting nitrogen in the reservoir to maintain high pressures which allows for high production rates. In fact the plant in the field produces more N2 than all the other outputs on the planet COMBINED. Two very important considerations in using pressure depletion drives in his model. First, the high decline rate he mentions. Second, unless there is some form of pressure maintenance such reservoirs tend to have the worst ultimate recovery percentage.

    The other major production system is water drive. In this case the reservoir pressure decreases very little if at all. I’m currently drilling hz wells in a field that has produced 28 mm bbls of oil since 1946 and the reservoir has dropped from 1900 psi to 1850 psi in 68 YEARS. Water drive reservoirs will produce with a very low decline rate until the water rises to the level of the perforations in the existing wells. In many cases when the well begins to “cut water” the operator will reduce the production by some degree to slow the encroachment of the water. Eventually many operators will using some form of pumping system to maintain as constant flow rate as possible in the early years. When the water cuts gets high many will increase the total volume lift as much as possible to increase the net oil production. Water drive reservoirs tend to have much higher ultimate recovery percentages then pressure depletion reservoirs.

    I won’t judge the rest of his analysis but by focusing on just the character of pressure depletion reservoirs he’s leaving out a huge percentage of the total oil production dynamic including some of the largest fields ever discovered.

    As far as operators deciding at what rate they produce their oil wells there are several factors involved. First, there a limit to how high a rate is produced. A well in a water drive reservoir might have the capability of flowing 800 bopd but the operator keeps it at 300 bopd because that higher rate might cause reservoir damage and potential collapse of the casing. Second, though some can withstand the revenue reduction most operators will continue flow their oil wells at max rate even when prices fall because they need to max the cash flow to cover their ongoing operations.

    I’m not an economist so I won’t quibble with him in that arena. But in terms of reservoir dynamics this guy doesn’t know sh*t so I have serious doubts about the validity of his model.

  3. Mark Ziegler on Wed, 31st Dec 2014 9:07 am 

    It is neither inferred nor implied that there is no limit to the wells that can be drilled.

  4. Nony on Wed, 31st Dec 2014 9:22 am 

    Model is fine. He’s just adding decision economics for capital into the Hotelling depletion framework. Not brilliant and I think a lot of people intuitively know this is how things work. But good that he does the model and confirms it.

    What he says about pressurization is pretty irrelevant to his model, which has to do with drilling decisions versus outlook for price.

  5. Joe Clarkson on Wed, 31st Dec 2014 10:44 am 

    Here’s a general question for all you oil experts out there. What proportion of worldwide oil production is sold on directly negotiated contracts that do not get bought and sold on a commodities exchange? Or conversely, what percentage of oil is actually purchased on the spot market?

    I think the answer bears on the response of spot prices to over or under supply.

  6. Apneaman on Wed, 31st Dec 2014 4:58 pm 

    Here’s how many wells de-pressurize themselves. I’m sure the fat cat drillers will be long buried in their gilded coffins when the grand kids get to deal with the consequence of this one too. Add it to the mountain of eco horrors we are leaving for our beloved descendants. Sorry honey, but grandpa needed that new Dodge Ram every couple of years and the four car garage to park it.

    Delaware-size gas plume over West illustrates the cost of leaking methane

  7. Speculawyer on Wed, 31st Dec 2014 5:32 pm 

    I think I know how they work. However, like everyone else, I have no idea how the various factors that play into oil prices will resolve themselves.

    No one can all the factors such as the European economy, development of shale fracking techniques, the Chinese economy, whether new oil deposits are found, the cost of batteries, whether wars will break out in oil exporting countries, what climate change rules will be passed, ICE technology improvements, what terrorist attacks will occur, tar sands extraction technique improvements, whether a grand bargain will be struck with Iran, incentive programs for electric & natural gas cars, whether Libya will sink into civil war, fuel cell technology improvements, etc.

    Knowing ALL of those factors is the hard part. Pretty much impossible.

  8. rockman on Wed, 31st Dec 2014 10:19 pm 

    “What he says about pressurization is pretty irrelevant to his model”. Absolute bullish*t. So his model treats wells at Ghawar, which produce thousands of bbls of oil for days, the same as Eagle Ford wells that deplete 50+% in just 2 years. His characterization of reservoir dynamics is ridiculous regardless of what he does with his model.

  9. rockman on Wed, 31st Dec 2014 10:35 pm 

    Joe – Hopefully this helps:

    We get the emails all the time: How do I get into ‘spot’ oil? The answer is, it depends.
    ◾The shifting definition of ‘the price of oil’
    ◾Separating contango from correlation
    ◾Real investment options

    Readers often ask, “How do I buy the spot price of oil?”

    The first question to ask is, which oil? West Texas Intermediate (WTI)? Brent Crude? Russian? Saudi Arabian? Oil from Dubai? The OPEC basket price?

    The U.S. Energy Information Administration (EIA) does a nice job collecting the weekly average spot oil prices from countries all over the world. Maybe that’s what you’re looking for?

    For most people, what they mean when they say “oil” is the oil they hear about on the nightly news or read about in the Wall Street Journal. If that’s the case, they’re not talking about spot oil at all. Instead, they’re probably referring to the price of the “front-month” oil futures contract trading on the New York Mercantile Exchange. That contract covers the price of West Texas Intermediate-grade oil, delivered on a specific date within the next month to a transfer hub in Cushing, Oklahoma, and it is the de facto reference for oil prices in the U.S.

    If you are reading the latest “This Week in Petroleum” from the EIA, you’ll notice that they have data not only on spot prices, but prices on four different futures contracts. That’s because they recognize that in the world of oil, spot and future are inextricably tied in the minds of the media.

    What Is The Spot Price?

    Still, the emails pour in: We want access to the spot price of oil.

    What does that mean?

    The spot price is what you would fork over to take physical delivery of that oil today. The EIA defines it as:

    The price for a one-time open market transaction for immediate delivery of a specific quantity of product at a specific location where the commodity is purchased “on the spot” at current market rates.

    The spot price is relatively unimportant in global oil markets. Most refiners purchase oil with the help of long-term contracts, either one-off privately negotiated contracts or contracts from an exchange.

    But the idea of spot price is one that fascinates investors – everyone is intent on trying to invest in something that tracks “the price of oil” as closely as possible. Why? To counteract that pesky profit eater – contango.

    As we cover in Hard Assets University, contango has a huge impact on investors in oil futures contracts. Contango is the situation where the “out-month” contracts are more expensive than the “near-month” contract. When that’s the case, there are real costs to allowing a contract to roll forward into the next month’s contract.

    In fact, contango can turn rising oil prices into a loss if it is steep enough. Just a few months ago, the contango in oil was so severe that simply investing in the front month created a 15% monthly headwind. That spurred a lot of emails asking how to access spot oil, as investors in oil futures saw their investments lag further and further behind oil itself. By investing in something that tracks the spot price of oil, an investor would gain (or lose) on the movement of oil itself – not on the need to roll a contract over at the end of the month.

    But how?

    Investment Vehicles

    As we have talked about before, there are many exchange-traded funds (ETFs) that focus solely on oil. Each ETF is structured slightly differently depending on the futures contract it holds, but all aim to give investors an easy way to invest in oil.

    Because of this, as you would expect, each of the ETFs are closely correlated with spot oil prices.

  10. Nony on Wed, 31st Dec 2014 11:07 pm 

    Not BS. Read the actual research paper. I have. The stuff about reservoir pressure is just intro stuff.

    His paper is not a paper on reservoir management. It’s a paper on drilling decisions.

    Seriously, break down and read the paper (not like when Rockdoc gave you those shale matrix papers and you blew him off) and you will see the point.

    You sometimes assume a curmudgeon corrective attitude without actually knowing what the topic is.

    Link to paper:

    It’s really not about pressure drive, Rock. It’s about capital budgeting decisions.

  11. Joe Clarkson on Thu, 1st Jan 2015 1:15 am 


    Thank you for very much your detailed response. I am not interested at all in investing in oil. I was just wondering about the relationship between the spot price and the average price of all barrels sold.

    I was guessing, and you confirmed, that the spot price is not the price that most oil is sold for. To get the true “price of oil”, one should take the average of every barrel sold rather than just those sold via contracts bought and sold on a commodity exchange. If exchange contracts are thinly traded in proportion to the overall volume, even small changes in supply and demand could make for a lot of price volatility in the spot market.

    I am sure that KSA, Russia and many other exporters are selling most of their oil on long term contracts at prices substantially higher than the current spot price. Six months ago they were probably selling for somewhat less than the spot price. I am guessing that there is a lot more inertia in the average price of all oil sold than the spot price.

    Does Platts or any other such publication attempt to collect and publish data on actual average sales prices? Years ago, when I had a small sawmill, I would read Random Lengths to get info on wholesale lumber prices. Is there something like that for oil? I bet the terms of most oil sales contract are proprietary, but it would surely be valuable information to know at what price the big players were actually buying and selling oil.

    Here’s another general question. I assume that virtually all crude oil is sold to refiners. If so, as you suggest, they must be purchasing a lot of their oil on long term contracts. They are probably also selling their output mostly on long term contracts. Why then do the prices of some refined products, such as gasoline, tend to follow the spot price? It seems that gas prices go up and down far more rapidly than one would expect, given the inertia in actual crude prices.

  12. Nony on Thu, 1st Jan 2015 1:23 am 

    1. GIYF on spot prices. (the EIA link is a good one.)

    2. Gasoline economics are based on supply and demand. Simple intuitions about arbitrage should make it clear why they will follow crude spot, rather than previous crude futures contracts.

    3. Peruse the values and you will see that spot is close to month ahead, usually well within a dollar and is about what you would expect in terms of fitting into the futures curve overall.

  13. rockman on Thu, 1st Jan 2015 12:01 pm 

    Joe – It’s even more difficult then that. I sell oil in Texas so you think I might sell it for the WTI price. I don’t: it’s barged to La. and my price is BASED UPON the La. Light Sweet benchmark. But I don’t sell it for the LLS price. I sell it for a price determined by my long term contract which starts with the LLS benchmark and the increased because my crude is a better quality but there’s also a decrease factor due to the transport cost.

    So what adjusted price do I get for my Texas crude shipped in La? You don’t know, do you? And you never will will because it’s none of your f*cking business. LOL. Just teasing but I don’t report that number to anyone except my partners and royalty owners. The Rockman and the other producers are not a Band of Brothers…we are competitors.

    The refiners know what they pay for every bbl they buy from every source. Now go find that number posted. Good luck. LOL. No one, producer or refiner, cares for our competitors to know the details of our business.

    In reality there’s very little oil sold exactly at any benchmark price. Remember when they talk about WTI at $X/bbl that’s probably the price you pay when you take title of oil stored in Cushing, OK. If that oil is sitting in my tanks in Texas you aren’t going to pay me as if the oil is sitting a few hundreds miles north. And if a refinery does buy 5 million bbls of oil physically sitting in Cushing storage what are they going to do with it when their plant is in La? Obviously pay to ship it there. So what did that refinery pay for that 5 million bbls of WTI: the posted price of WTI Cushing, WTI Cushing + transport cost, WTI Cushing based on their long term purchase contract calculation, WTI Cushing Spot Price or WTI Cushing Spot Price + transport cost to their refinery?

    And it isn’t even that simple: I might buy 5 million bbls at WTI Cushing and then swap that oil with a Nebraska refinery for 6 million bbls of Venezuelan heavy they bought on the spot market…the spot market FOP Venezuela. So who paid how much for each bbl?

    Want to make it worse? I don’t sell my Texas oil at an adjusted LLS price to a refinery. I sell it to Plains Resources, which is engaged in the transportation, storage, terminalling and marketing of crude oil. They then sell the oil to refineries. And I don’t have a clue of what that price might be. Except that it varies from refinery to refinery. And that some of those sales are based upon long term contract positions and some on the spot market.

    So there you go: it should as clear as mud now. LOL.

  14. rockman on Thu, 1st Jan 2015 12:30 pm 

    Joe – Forgot to mention the foreign oil market and how pricing works with National Oil Companies and the oil companies (IOC’s) involved in developing their oil resources:

    “A buyback service contract consists of two separate parts: the exploration and development service contract, which covers the development phase of a field, and the volume-based, long-term export oil sales agreement (LTEOSA), which regulates the reimbursement of costs and a return in the form of oil or gas, not cash. While the contractor develops the field, NOC repays the capital expenditure, operating expenditure, and accrued bank charges. The contractor also receives an agreed remuneration fee, normally by way of an entitlement to an amount of produced hydrocarbons. The IOC gains lifting rights to a portion of crude and a contractual right to equity oil, which helps its balance sheet. The LTEOSA continues until the contractor has fully offset its petroleum costs and the remuneration. The IOC is usually committed to a development period of 2-3 years and a 5-8-year operation period.”

    So consider China’s involvement in the development of offshore Angola oil. China ships X millions of bbls of that oil back home. So what did China EFFECTIVELY pay per bbl for that oil? And what if China sees an advantage of selling a 5 million bbl tanker load to Germany on the spot market next February when the EU gets hit with a nasty polar vortex…what did China pay for the oil they marked up and sold to Germany?

    And lastly there are “net back” deals. For instance may sell oil on long term contracts to refinery X. But if that refineries buys more oil then planned the KSA might refund a small portion of that $/bbl. Also works that way with many US car dealerships and the car makers.

    I’ll stop now…this is giving me a headache. LOL. I’m sure you understand now why I’ll occasional rant and race about generalities like “Eagle Ford oil is selling for $X/bbl” or “Venezuela will make $Y million next month by selling Z bbls of oil”. There’s nothing wrong with using generalities as long as we remember that in some specific cases those generalities are greatly in error.

  15. Joe Clarkson on Thu, 1st Jan 2015 11:11 pm 

    Aloha Rockman,

    Thank you again for your explanations of oil pricing. Since it is pretty clear that spot and future prices don’t have a whole lot to do with current sales price averages (except perhaps as leading indicators), I can take the recent oil price plunge with a large grain of salt. It may very well be true that the Saudis, and other large producers, are not too worried about the current spot price, since they have pre-sold most of their production at much higher prices.

    They may not be very worried about the effect of loss of revenue on their budget just yet. But if spot prices stay down for long enough, it will probably affect the re-negotiation of not only their long term contracts, but also those of other players, including your company.

    The same probably holds for shale producers who have hedged their production. It may take many months for the recent plunge in spot prices to actually affect a shale producer’s revenue too.

    But I can imagine that future production will take a big hit, even though current production remains profitable. Few high cost producers will want to take the chance that these lower prices will ‘stick’, so they may cut back on any un-hedged new production. It will be interesting to watch how it all unfolds.

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