The Keystone XL Pipeline: A Risky Bet on Higher Oil Prices and Tight Oil

Posted in The Petroleum Truth Report on February 3, 2017

The Keystone XL Pipeline (KXL) is a bet on much higher oil prices several years from now.  It will take at least $85 oil prices to develop the new oil sand projects needed to fill the pipeline.

It is also a bet that U.S. tight oil output will continue to grow and will need heavy oil to blend for refining. Both bets are risky.

A Bet On Higher Oil Prices

KXL would add about 830,000 barrels per day (b/d) to the 1.3 million b/d already moving through the base Keystone Pipeline system completed in 3 phases between 2010 and 2014 (Figure 1) when oil prices were more than $90 per barrel.

Keystone & Keystone XL Map 29 Jan 2017

Figure 1. Location map of Keystone XL and Base Keystone pipeline systems. Source: TransCanada and Labyrinth Consulting Services, Inc.

It was not until prices exceeded $70 per barrel in 2005 (December 2016 dollars) that oil sands expansion began to accelerate (Figure 2). Since then, production has almost doubled from 1.3 to 2.4 mmb/d and cumulative production has increased from 5.4 to 10 billion barrels.

Oil Sands Production Accelerated at $30 and $70 per Barrel

Figure 2. Oil Sands Production Nearly Doubled After Oil Prices Exceeded $70 Per Barrel. Source: Statistics Canada and Labyrinth Consulting Services, Inc.

By comparison, the Bakken and Eagle Ford tight oil plays have each produced 2.4 billion barrels. The Permian horizontal tight oil plays–Spraberry, Wolfcamp and Bone Spring–have produced less than 1 billion barrels.*

Oil Sands-Tight Oil Cumulative Comparison Table FEB 2017

Table 1. Comparison of Oil Sands and U.S. tight oil plays. Source: Statistics Canada, EIA, Drilling Info and Labyrinth Consulting Services, Inc.

In 2015, oil prices averaged only $43 per barrel. No new oil sand projects have been sanctioned since oil prices collapsed in 2014 although 3 pilot projects have been approved since prices moved into the $50 per barrel range. Approval is not the same as sanctioning and these 3 projects together would add only 35,000 b/d.

It seems unlikely that new greenfield projects will be sanctioned until oil prices move much higher (Canadian heavy oil (WCS) trades at a 25% discount to WTI). Assuming that prices stabilize in the $50 to $60 range, it is reasonable that pilots may evolve into brownfield expansion projects over the next year or two.

The Canadian Association of Petroleum Producers estimates that annual oil sand production will grow 128,000 b/d until 2021 and then, grow more slowly at 59,000 b/d. If all of that new oil were going to KXL, it would not reach capacity for about 10 years. But other pipelines are already approved for expansion and will probably get much of the oil before KXL is completed.

TransCanada’s bet, therefore, is that oil prices will move much higher and more quickly than most forecasts anticipate and that the volumes will be there by the time that the pipeline is built.

Light Oil and Heavy Oil

U.S. tight oil plays produce ultra-light oil. Almost all of it is too light for refinery specifications. That means that it must be blended with heavy oil in order to be refined and that is why there is demand for Canadian heavy oil.

The Keystone XL Pipeline is, therefore, a bet that tight oil plays will continue for several decades.

Similarly, Canadian viscous, heavy oil must be diluted with ultra-light oil to move through pipelines. Because of that, Canada is the biggest importer of U.S. light oil.

The U.S. imports almost 3 times more oil from Canada than from Saudi Arabia (Figure 3). Imports from Canada are roughly equal to the amount from Saudi Arabia, Venezuela, Mexico, Colombia and Iraq combined.

The U.S. Imports Almost 3 Times More Oil From Canada Than From Saudi Arabia

Figure 3. The U.S. imports almost 3 times more oil from Canada than from Saudi Arabia. Source: EIA and Labyrinth Consulting Services, Inc.

The average U.S. refinery is designed for 31° API gravity oil but 80% of domestic crude oil is more than 30° and 70% is more than 35° API gravity so it must be blended with heavier oil before it can be refined (Figure 4). The Keystone Pipeline carries oil that is approximately 22° API so the fit with lighter U.S. oil is perfect.

80% of U.S. Crude Oil > 30 API and 70% > 35 API

Figure 4. 80% of U.S. Crude Oil is greater than 30° API and 70% is greater than 35° API. Source: Drilling Info, EIA, Labyrinth Consulting Services, Inc. and Crude Oil Peak.

The increasing percentage of ultra-light oil (>40° API) after 2011 shown in Figure 4 is because of the growth of tight oil plays. More than 95% of tight oil is greater than 30° API and these plays now account for more than half (52%) of U.S. output.

It is, therefore, no surprise that 98% of the oil imported by the U.S. is heavy that is, less than 35° API gravity (Figure 5). The biggest sources of heavy oil other than Canada are Saudi Arabia, Venezuela and Mexico.

98% of U.S. Imports Less Than 35° API Gravity

Figure 5. 98% of U.S. Imports Less Than 35° API Gravity. Source: Drilling Info, Labyrinth Consulting Services, Inc. and Crude Oil Peak.

Production from Venezuela and Mexico is declining (Figure 6). Canada, Iraq and Saudi Arabia have strong production histories and are, therefore, more reliable long-term providers of heavy oil to the U.S. Canada has many advantages over other providers because of geographic proximity, supply security and price.

Mexico, Venezuela, Nigeria and Angola Have Declining Production

Figure 6. Mexico, Venezuela, Nigeria and Angola Have Declining Incremental Production. Source: EIA and Labyrinth Consulting Services, Inc.

Venezuela has enormous reserves of heavy oil and declining production is mostly because of political and social instability. This could change but it is more likely that Venezuela’s problems will continue. Mexico’s production decline is more systemic because the country has not made a significant new discovery since 1980.

A Bet on Tight Oil

So far, so good for the Keystone XL Pipeline but what about the longevity of the tight oil plays?

Production from the Bakken and Eagle Ford plays is in marked decline and Permian tight oil production growth has slowed (Figure 7). This is despite record high numbers of producing wells in all 3 plays.

Eagle Ford-Bakken-Permian PROD by API 1 FEB 2017

Figure 7. Bakken and Eagle Ford production are declining and Permian basin tight oil production growth has slowed. Source: Drilling Info, Labyrinth Consulting Services, Inc. and Crude Oil Peak.

The Bakken and Eagle Ford plays have probably peaked based on remaining core area locations, generally poorer performance from recently drilled wells compared to older wells, and current rig activity. Assuming that oil prices recover to the $70 range in coming years, production should increase as more marginal locations become economically viable–just not to peak levels reached in 2015.

The Permian basin, on the other hand, should continue to grow for several years for all of the reasons that the Bakken and Eagle Ford will not. There are substantial areas in the Permian core that have not been fully developed. Well performance continues to improve and the horizontal rig count has increased 70% since mid-August to 243.

Most forecasts are optimistic about tight oil output. The EIA Annual Energy Outlook 2017 anticipates that tight oil production will decline in 2017 but recover to 2015 peak levels by 2019 (Figure 8). WTI oil prices are expected to be $64 per barrel then and slowly increase to $80 by 2025. Tight oil production will rise to 6 mmb/d by 2026.

EIA Forecast- Tight Oil Will Not Recover to 2015 Levels Until 2019

Figure 8. EIA Forecast: Tight Oil Will Not Recover to 2015 Levels Until 2019 and Then Increase to 6 mmb/d by 2026. Source: EIA AEO 2017 and Labyrinth Consulting Services, Inc.

Although the forecast seems reasonable, it assumes that 2016 was the oil-price floor and that prices will continue to increase. It also suggests that prices will not reach the $70 threshold for new oil sand projects for 5 years. Other forecasts like HSBC are more aggressive and anticipate mid-$70 WTI prices as early as 2018.

The Big Long

If the last few years since the oil-price collapse have taught us anything it is that prices are unlikely to move in one direction. Nor are they likely to conform to mainstream analyst views.

Markets have been driven partly by an expectation that prices must inevitably return to levels of at least $70 to $80 per barrel sooner than later. This belief has endured despite a persistent global supply surplus and outsized inventories. The long-anticipated OPEC deus ex machina was lowered onto the stage in late 2016 and markets responded enthusiastically. Yet WTI prices have not crossed $55 per barrel so far.

It is difficult to find supply-demand fundamentals support even for the limited price rally that began with the OPEC announcement.  There may already be an expectation premium of $10-12 per barrel built into current prices. Yet markets don’t always follow fundamentals in the short term although they return to them eventually.

U.S. ultra-light oil production is a central component of the global supply dilemma. Permian basin companies are adding rigs like the boom days of 2011 to 2014 have already returned. When tight oil output is high, some fraction can neither be refined nor exported and simply adds to inventories. This occurs despite the best efforts of Canadian oil sand producers to bring as much heavy oil to the party as they can.

Oil consumption remains relatively weak in the U.S. This is disturbing against the backdrop of surging tight oil rig counts.

Consumption increased with very low oil prices in 2015 and early 2016 but not to the levels before the Financial Collapse of 2007-2008 (Figure 9). Most of the increase was from greater gasoline use and more refined products exports. Modestly increasing prices in 2016 dampened consumption suggesting that demand is highly price-sensitive.

Consumption Fell >2 mmb-d After 2005 But Recovered

Figure 9. Consumption fell >2 mmb/d after 2005 but recovered 1 mmb/d with increased refined product exports, lower oil prices & increased gasoline use. Source: EIA and Labyrinth Consulting Services, Inc.

This does not represent peak demand.  All credible forecast anticipate oil-demand growth over the next decade or so, albeit at a slower rate. Instead, it reflects an economy weakened by excessive debt and changes in Federal Reserve Bank monetary policy after mid-2014.

These rather gloomy observations may explain TransCanada’s motivation to complete the Keystone XL Pipeline now. I’m talking about a long bet on oil prices.

Future supply constraints will become greater the longer new E&P project investments are deferred. At the same time, the decline of production from developed fields will be more pronounced. Improved production efficiency will further accelerate reserve depletion. Meanwhile, new field discoveries are at the lowest level in decades and the average reserve size of those discoveries has gotten smaller.

Oil prices will increase dramatically at some time in the next several years. That should lead to the next oil boom and the Keystone XL Pipeline will be there to provide heavy oil to U.S. tight oil plays.

There is little doubt that a supply crunch lurks in the future. The risk for the Keystone XL is that much higher prices will collapse the global economy before new projects can fill the pipeline and pay out the investment.

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*EIA’s Drilling Productivity Report estimate of 4.8 billion barrels includes all conventional production in the counties in which the tight oil plays are located.

Matt Mushalik contributed to the research on light oil.


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12 comments on this entry


  1. Another great article. I do wonder if this pipeline will outlast the next wave and then some. Estimates are for a 50 year lifespan, but many pipelines are still going strong well past their (low estimated) lifetime, and that’s with out modern maintenance. With potential extension to the west coast there’s plenty of other moderate to heavy oil that can be pushed into the picture going into the future. Alaskan North Slope is 32.3 for example, and although Caelus’ discovery last year was light, there’s more to be found, no doubt.


  2. Jesse,

    Thanks for your thoughts. The relationship of refinery capacity for different grades of oil is not on most people’s radar screens. They think that oil is oil.

    Those opposed to KXL argue that most of the oil will be exported. Although that may be notionally correct, the truth is that much of domestic oil cannot be used without heavier oil for blending. We will get it from somewhere if not from Canada–probably Saudi Arabia.

    The environmental opponents of KXL focus on the peculiar composition of the oil sands oil and think it will create a bigger mess than most oil spills if there is a problem. As far as I can tell, that is probably true if the spill is into water because the volatile diluent will quickly evaporate and the bitumen will fall to the bottom. On land, however, it seems that the opposite is true: once the condensate evaporates, it should be relatively easy to scoop up the solid bitumen.

    Then, there are those who are just opposed to anything that contributes to more fossil fuel usage. I’d like to know how much they use their cars and electric power not to mention manufactured goods that rely on fossil fuels.

    I try to stay neutral and objective on these subjects but I honestly wonder if those opposed to KXL understand the issues.

    All the best,

    Art


  3. Another great article Art. I am always impressed with the concise, accurate language you use and the excellent figures with careful use of color. Your continuing contribution to the understanding of complex information and data in the oil and gas industries is outstanding and makes me proud to be a fellow geologist.


  4. Conrad,

    Thanks for the comments. I must admit that this post was among the most difficult that I have written because there are so many potentially convoluted layers to the story. It was challenging to figure out how to say it all without causing too much confusion.

    All the best,

    Art


  5. well, you did a fine job Art


  6. Great article Art. Have not seen the relationship between Keystone XLP and lower 48 production explained this way. You outline a rather marginal scenario for the pipeline economics with a very long payout at best. It seems that a couple new refineries or modifications to existing refineries capable of refining higher gravity crude oil could also potentially solve the feedstock problem you outline in the article. Do you suppose any downstream companies are seriously considering “this” option given the new administration’s EPA chief? Seems that an investment in refinery capacity capable of using higher gravity oil would be a potential substitute to Keystone XL with much lower risk, less capital intensive and a shorter payout. Surely with Scott Pruit as EPA chief someone in the industry is thinking about this…


  7. Jeff,

    Those are good questions and difficult to answer. There is a report by by AFPM and another by Baker & O’Brien that discuss planned absorption of light oil from U.S. tight oil plays. Both are based on surveys and were done when oil prices were $90+/barrel so there are some real questions about how much of what they described has materialized. In any case, both suggest that full potential to absorb all light oil production is feasible by 2020 or so.

    I imagine that at today’s somewhat lower production rates, most of the light oil can be absorbed although some probably just goes into storage. I assume this because otherwise, there would be an explosion of inventory beyond the high levels we have observed since oil prices collapsed in 2014. The bottom line, however, is that I don’t know and have not found a way to learn the truth. The real issue is at what point it makes more sense to expand capacity vs. just buying relatively cheap oil for blending. If there is money to be made, I assume that capacity has and will be added. The light oil is worth more than heavier grades because of the ease to refine it into gasoline and diesel.

    All the best,

    Art


  8. Hi art,
    What about your idea related to this huge increase in wti stock this week?
    Thanks Marco


  9. Marco,

    The increase in storage was mostly because of imports.

    null

    I suspect that a lot of oil was left on tankers at year end to avoid swelling taxable stockpiles and that it all came to port in January.

    Thanks for your question,

    Art


  10. Hi art,
    please could you clarify this point.
    EIA storage report consider wti stock ( light oil ) so why have you considered in the computation, to give an explanation of the huge stock increase, import oil too that I suppose to be brent oil ( heavier oil ) ?
    As you remarked in a different article brent oil is a different kind of crude oil so it wouldn’t have been considered an addendum of the sum.
    there is something of wrong in my way to think?
    Thanks Marco


  11. Marco,

    The EIA storage report is for all U.S. crude oil stocks–all oil at refineries, tank and underground storage–not just domestic field production (WTI). So, imported oil is included in storage and the U.S. imports almost half the oil supply.

    Taxes must be paid on crude oil inventories based on year-end accounting so refiners try to deplete their stocks in the final weeks of each year. That resulted in a lot of imported oil in tankers waiting on delivery to ports that happened in a big way over the past few weeks.

    Imported oil comes from many places but most is from Canada, Saudi Arabia, Venezuela and Mexico so very little U.S. imported oil is “Brent.”

    I hope that this helps clarify your confusion.

    Art


  12. Ok Art. Thanks as always for your availability.