U.S. Energy Independence: Bakken Helping Pave the Way

Pumpjack Panorama with Canadian Rockies in Distance
© DTC Energy Group, Inc. 2013

Major technological advancements in drilling and completing oil and gas wells over the past five years helped make North Dakota’s Bakken Shale one of the most successful oil fields in U.S. history. Boasting an estimated mean resource of 3.65 billion barrels of oil, according to the U.S. Geological Survey, the Bakken stands to be a significant contributor to U.S. energy independence. Without the changes in technology that have taken place, recovery of reserves in this unconventional play would not be feasible.
In just five years, advancements in tools, techniques and petroleum technology have
revolutionized Bakken drilling operations by improving overall well performance, reducing drilling time, cutting costs and minimizing the environmental footprint. The primary keys to improving well performance have been increasing lateral lengths and fracture stages, as well as changes to well completion techniques.
Serving on the front lines of drilling and completion operations for a variety of operators in the
Bakken, on-site supervisors for DTC Energy Group, Inc., a Denver-based petroleum operations consulting firm, have been significant contributors to these trends.



A combination of advanced drilling technology and the eco-friendly concept of pad drilling has significantly reduced drilling time, costs and environmental impacts for operators while allowing for the construction of significantly longer laterals and greater production potential.
DTC Energy Group drilling supervisors have contributed to the doubling of lateral lengths (the horizontal section of wells) in the Bakken with increases from 5,000 feet in 2008 to approximately 10,000 feet in 2013. The corresponding total depth (TD) of wells has increased from roughly 16,000 feet five years ago to 21,000 feet today.
Advancements in drill pipe design have enabled the drilling of longer laterals. Newer style drill
pipe allows for increased maximum torque, enabling drilling to greater horizontal depths without damaging the pipe or connecting threads.

Longer laterals are allowing for more fracture stages along the horizontal section of the well and thus increased production. Bakken and Three Forks oil production figures from the North Dakota Department of Mineral Resources show a significant jump since the beginning of 2008, going from an average of just over 75 barrels per day per well in early 2008 to 130 barrels per day per well in 2013.
In addition to drilling an extra 5,000 feet or more, the time to drill a well to TD has decreased significantly. Five years ago, 16,000-foot wells were taking an average of 32 days to drill. Now, the average drill time for 21,000-foot wells is 18 days or less. Sometimes these wells can be drilled in as few as 12 days. With drilling operations now costing up to $70,000 per day, the reduced drilling time equals big savings for operators and investors.

Such a significant reduction of drilling time is due in large part to several major factors, including the replacement of old rigs with fleets of newly-designed rigs that utilize top drives. Additional factors include increased performance of directional down-hole tools and the concept of pad drilling.


The Bakken has experienced extensive rig upgrades in the past decade, replacing many 30-year-old rigs and adding top drives, devices used to better manipulate the drill string during the drilling process. These
upgrades are the primary reasons operators are able to drill such longer laterals in such a shorter period of time.

“Top drives can drill 95 feet without making a drill pipe connection. Before top drives, we could only drill 30 feet at a time,” explained DTC Energy Group Drilling Supervisor Milo Brown. “Top drives have been in use for many years but didn’t start making an appearance in the Bakken until roughly five years ago, mainly because of their high cost. Due to their time-saving ability and versatility, top drives are now being used on the overwhelming majority of rigs in the Bakken today.”


In addition to newer style rigs and the extensive use of top drives, increased performance of directional down-hole tools has also contributed to shorter drilling time and the ability to drill longer laterals. Measurement While Drilling (MWD) tools are now able to drill without battery or electronic failures that were common with older designs, saving more time. MWD’s, along with mud motors, can now also withstand higher temperatures and amounts of shock and vibration that occur in vertical and horizontal
“Besides new rigs and top drives, new mud motor technology and drill bit technology have led to enormous advances in the speed at which you can drill,” said Luke Clausen, DTC Energy Group chief operations officer and co-owner. “Five years ago, if you were able to drill 3,000 feet in the first 24 hours after drill-out, you were doing great,” Clausen continued. “Now that number is 5,500 feet. You have mud motors being built better with much lower failure rates. Drill bits are being made much better. The whole drilling package has improved.”


Pad drilling, which involves drilling multiple wells from one drill site, has also been a major contributor to reduce drilling times and environmental impacts, as well as improving well economics, in the Bakken.
“During pad drilling, we complete the well into the projected formation, run the casing and
cement and then walk or skid the rig 40 feet to the next well to do the same,” explained Brown.
Once the last well on the multi pad is cemented, drilling and pipe changes are conducted before the horizontal sections are drilled.
“This process eliminates the need for laying down drill pipe, cleaning mud tanks and picking up the horizontal pipe on every well,” Brown continued. “It also eliminates rig moves between each well.”
Moving a rig from one drill site to another can take days, while “skidding” a rig over to the next well on a pad only takes a few hours. Pad drilling is also helping to reduce the environmental footprint left behind by the drilling process. With multiple wells now being drilled at one site, fewer drill sites are needed, and thus less surface area at ground level is being affected by the drilling process.


While the cost of new rigs, top drives, advanced tools and skilled personnel to drill wells in the Bakken have increased in the last five years, the time spent to drill a well to TD has decreased. Drilling costs have gone from roughly $40,000 per day in 2008 to up to $70,000 per day in 2013, but the drastic increase in
estimated ultimate recoveries (EURs) and the impact of shorter drilling times has reduced overall drilling costs and improved internal rates of return (IRRs) for oil and gas companies.
The average total drilling cost in 2008 was roughly $2.5 to $3 million for a $15,000-foot well,
while a 20,000-foot well often cost as much as $3.5 to $4 million. In 2013, the average total drilling cost for a 21,000-foot well is approximately $3 to $3.5 million.
Oil and gas operators in the Bakken have seen EURs for dual laterals increase from an average of approximately 375,000 barrels of oil in 2008 to more than 600,000 barrels of oil equivalent in 2013.



The combination of longer lateral lengths and advancements in completion technology has allowed operators to increase the number of frac stages during completions and space them closer together. The result has been a higher completion cost per well but with increased production and more emphasis on profitability.
In the past five years, DTC Energy Group completion supervisors in the Bakken have helped oversee a dramatic increase from an average of 10 stages in 2008 to 32 stages in 2013. Even 40-stage fracs have been achieved. One of the main reasons for this is the longer lateral lengths – operators now have twice as much space to work with (10,000 versus 5,000 feet along the lateral). Frac stages are also being spaced closer together, roughly 300 feet apart as compared to spacing up to 800 feet in 2008, as experienced by DTC supervisors. By placing more fracture stages closer together, over a longer lateral length, operators have successfully been able to improve initial production (IP) rates, as well as increase EURs over the life of the well.


Sliding sleeve and plug-and-perf methods are two primary fracturing and stimulation techniques now used for zonal isolation in complex multi-stage fracs in the Bakken. Before sliding sleeve technology was more recently introduced in the Bakken, plug-and-perf stimulation was the primary completion method being used. Today, it varies greatly from operator to operator whether sliding sleeve, plug and perf or a combination of the two techniques is used.
The principal factors in deciding between the two techniques are cost savings and the ease and
quality of the frac. Sliding sleeves take less time, roughly a day and a half, to complete a well, while the plug-and-perf method can take several days. The time saved with the sliding sleeves generally results in lower costs for the operator. However, some operators swear by the plug-and-perf method and hold that it results in a better frac due to its ability to provide better certainty in frac delivery and allowing subsequent access to the horizontal wellbore.
Some operators use a combination of the two techniques on the same well – a practice that is called a hybrid frac. In a hybrid frac, sliding sleeves are often used in the first 10 to 20 stages at the toe (far end) of the well, where it is more difficult to use the plug-and-perf method. After that, plug-and-perf is performed on the remainder of the well. Using a combination of the two techniques can also help ensure a successful frac. If one method experiences failures, the other can help mitigate the impacts on the well. Regardless of which technique is used, the increased number of frac stages being used in the Bakken is resulting in better production and recovery of oil and gas.


Apart from the higher number of frac stages, changes in proppants used during fracing have also
enhanced production in the Bakken. Proppants are small particles, such as sand or ceramic grains, that are injected with fluid into fractured rock and remain there to hold fractures open while allowing reservoir fluids to flow into the well. Ceramic, or man-made, proppants are very strong and have had the greatest impact after being introduced in the Bakken roughly five years ago. “When I was a kid, it was the equivalent of beach sand that was being used for fracing,” said James Bentley, DTC Energy Group completion supervisor. “Now it’s ceramic proppant that can’t be crushed. That allows for much better production. Ceramic proppants cost more, but it’s worth the longer production life of the well.”
The types of proppants used during fracing in the Bakken vary from operator to operator, but many choose to use a mix of white sand, resin-coated sand and ceramic proppants for different stages of the completion process.


In terms of cost, completion operations are more expensive now than five years ago. Simple 10-stage frac jobs on a 5,000-foot lateral cost an average of $500,000 five years ago with the total cost of completion being $1 to $1.5 million. Today, on the high end, complex 30-stage frac jobs on 10,000-foot laterals are costing as much as $3 million ($100,000 per stage) with a total completion cost of $5 to $5.5 million. Overall, the average cost per frac stage now is roughly $70,000. However, completions costs vary greatly depending on a variety of factors, including lateral length, the number of frac stages and types of tools, proppants, fluid additives and pumping unit used.
In addition to a high level of variation from operator to operator, the rapidly changing technology
and advancements are also causing costs to constantly fluctuate, making it more difficult to accurately chart a trend in the industry. There are indications that the increased overall cost of completions may be reaching a plateau and that costs may be starting to decrease, if they haven’t already. What is certain is that better tools and technology are allowing for much more successful fracs with productivity improving at a higher rate. These advancements are also providing a more environmentally-friendly approach.


“Fracing is a water-sensitive issue, and some of the biggest changes we’ve seen over the last few years are the reuse of water and the potential for treating water,” explained Robert Sylar, chief executive officer and co-owner of DTC Energy Group. “We’re also minimizing the fluid additives involved in the fracing process.”
The oil and gas industry is making great progress in total water management solutions with new
innovations allowing for more effective and cost-efficient recycling and reuse of water used during fracing. In other shale formations, it is not unusual for as much as 90 percent of flowback and produced water to now be recycled, when formerly, this water was trucked to disposal wells or other disposal facilities.


Overall, the significant advancements that have taken place in drilling and completion operations in the Bakken over the past five years are helping lead the U.S. on a path toward energy independence. Wells in the Bakken and all other major shale areas of the U.S. are being drilled and completed faster and producing more oil and gas than ever before. In addition, these advancements are helping to significantly reduce impacts on the environment, while the overall success of the Bakken continues to generate jobs and improve our economy. More innovation and faster application of even newer techniques are coming in the very near future.
American companies and universities along with our government’s national energy laboratories are all working to propel the rapid rate of change and ensure that our economy has the energy advantages it needs. The U.S. Department of Energy’s National Energy Technology Laboratory in Tulsa, Okla, is devoted to fossil energy research and enabling domestic fossil fuels to economically power America in an environmentally sound manner. Many universities have programs focused on developing cleaner, more efficient energy while protecting the environment. The University of North Dakota is one example with its Energy & Environmental Research Center. American companies are also taking part in the effort.
Brine Chemistry Solutions, for example, created The Shale Water Research Center, aimed at making hydraulic fracturing more efficient, while “maintaining a zero or net positive environmental footprint”, according to their website. Changes are taking place across the industry and our nation to create a brighter energy future for America.

By Heather Siegel – Denver, CO

_____________________________About the Author:

Heather Siegel, assistant director of marketing at DTC Energy Group, Inc., is also a meteorologist with a degree from the University of Oklahoma and member of the Society of Petroleum Engineers. Prior to joining DTC Energy Group, she worked as a meteorologist and online journalist for AccuWeather. Some of her previous articles and research include long-­‐range seasonal forecasts for the United States and Europe, as well as outlooks on the effects of hurricanes on oil and gas prices. In her position at DTC Energy Group, Ms. Siegel is continuing her passion for forecasting and trends by writing about the oil and gas industry.


Oil pump oil rig energy industrial machine for petroleum in the sunset background for designOil pump oil rig energy industrial machine for petroleum in the sunset background for designOil pump oil rig energy industrial machine for petroleum in the sunset background for design

PART 1 – Background and Definitions

J. Reader, Barchan Advisory Services Ltd. ©

This is a broad and complicated topic, so it makes sense to break the discussion up into a few parts. First of all, a little background will illustrate the relevance of the topic. Then, it’s important to clarify what is meant by the terms. Ultimately, the goal is to investigate the implications of the new types of plays that are changing the dynamics of the oil and gas sector. The focus here is on tight unconventional reservoirs, not to be confused with unconventional bitumen projects.


Within the last decade the bulk of upstream oil and gas capital has been directed to a new class of plays – the unconventional plays. A steady increase in commodity prices has driven new technology and has resulted in a fundamental turnaround in North America from one of a depleting supply to a growing supply. This is hugely important to our western economy as it has attracted significant capital, created a technological renaissance and has spread significant wealth into local petroleum-­- based economies that were thrown into turmoil starting in 1986 when oil prices plummeted from the highs of the 1970’s and early 1980’s.

In 1956, Hubbert hypothesized that hydrocarbon production would peak in the late 1960’s or early ’70’s, and then relentlessly decline. This theory, a mantra of doomsayers for some time, has been challenged by the recent apparent abundance of production in both oil and gas in the US and in Canada. Industry pundits are now predicting a drastic continental over supply in both oil and gas, something that would have been laughable not that long ago. The chart below shows the history of US production and a recent forecast. Clearly after a long steady decline, these new plays have broken the trend.

So, what is behind this revolution? Fundamentally, the industry is transitioning from using technology to search for hydrocarbon accumulations, to using technology to extract hydrocarbons from known, but previously uneconomic accumulations. The driving force comes from the top line – commodity prices that are high enough to pay for the cost of developing and applying new technical approaches that would previously been considered pointlessly expensive.

There has been a profound shift in industry parameters. No longer can the sector be considered low cost. The need for capital influx to the business in order to sustain production levels has changed its ownership structure. The quality and certainty of reserves estimations is in flux, and the nature of portfolio production declines is different. The required skill sets of the workforce have changed. Finally, the nature of exploitation of these new resources has raised significant questions about the environmental impact of this exploitation, even in an industry that hasn’t been considered low impact in the past.

Disclaimer Respecting Reservoir Engineering

Before proceeding to discuss the nature of conventional and unconventional tight reservoirs, it is important to emphasize that this is a complex engineering subject. Furthermore, there are various informed opinions on how to best understand the distinctions between reservoir types, and not all these opinions will agree on all points. Here we provide only the most high-­-level perspective on the topic. Our goal is to provide a framework for discussing the important economic differences between types of plays. It is not to provide a course in the physics of reservoir engineering.

Defining Conventional Reservoir Performance

Oil and gas is naturally stored in rock reservoirs and produced to the surface through well bores drilled to the depth of the reservoirs. In order for the hydrocarbons to get to the well bore they must have enough energy (in the form of pressure) to migrate through the rock to get there. The pressure is provided in one form or another by the depth of burial of the reservoir and this pressure must be sufficient to overcome the resistance to flow resulting from the tiny holes in the rock called porosity. The tinier the holes are, the more resistance is encountered.

A simple end member of examples is the single hole reservoir with maximum porosity which for illustrative purposes could be like your propane BBQ tank. Open the valve and the flow begins. The friction resulting from the valve size restricts the maximum flow, but otherwise it generally does exactly what a conventional reservoir does. The flow starts out high and immediately starts to drop as the pressure in the tank begins to decline. The pressure at any time is related directly to the cumulative flow. The flow declines in a constant ratio to an amount of time that has lapsed. In other words, the decline rate is constant with time and the flow declines exponentially.

Think of the propane tank full of sand and the single valve replaced with many sand-­- sized micro-­-valves and you are getting closer to the real earth model. Regardless, the same relationships between pressure and flow are there, and the decline rate to a first approximation is constant. The resulting production profile for a constant 20% decline rate is shown on the blue line in the next chart. Note that, the highest flow rate is at the beginning and the production falls off in an orderly manner with time.

Before moving on to the unconventional tight reservoir, a few further qualifying comments need to be made. Although a propane tank simulates our gas reservoir, oil reservoirs have the same mechanisms. After all, the propane in the tank under pressure is in a liquid state, just like oil. The expansion of gas dissolved in the oil drives the liquid components to well bore. Our simple sand reservoir can also be made far more complicated by geological processes so that the flow is more confused and the decline characteristics can vary slightly over time and between different reservoirs. Other pressure-­-related processes can interfere with the decline, such as natural or artificial water movement in the reservoir, and artificial changes to the pressure at the surface where the product is collected.

Nevertheless, the conventional reservoir performs in a reasonably predictable fashion and can be modeled using engineering methods developed over the last eighty years. The ultimate recovery of oil and gas can therefore be predicted with some confidence, and the performance of additional wellbores yet to be drilled can be reasonably estimated. Also, the decline rates in the majority of cases are modest

  • – ranging usually between 10% and 30% per year over the life of the field.

Defining Tight Unconventional Reservoir Performance

Today’s tight reservoir performance is typified by a few key characteristics:

  • The hydrocarbons are stored in extremely small pores, some of which are close to molecular sizes.
  • A conventional vertical wellbore into a tight reservoir will almost always fail to flow at an economic rate, if it flows at all.
  • Long horizontal wells are required to achieve commercialization.
  • Modern, multi-­-staged, high-­-pressure fracture stimulations are essential (fracs).
  • Initial decline rates are dramatic and decline rates change over time.
  • Individual wellbore performance is unpredictable, so that statistical methods must be used to estimate reserves.

Understanding why and how these parameters occur is a necessary preliminary to unraveling their implications for today’s oil and gas sector. Here we review them in order:

Extremely Small Porosity and No Conventional Flow

Tight reservoir wells are often referred to as shale gas or shale oil wells. Shale is the deeply buried ancient equivalent of modern mud. Traditionally shale is so impermeable to hydrocarbons and water that it has been viewed as a capping reservoir seal, as opposed to a reservoir itself. Shale however is full of the organic material that generates hydrocarbons and so it is not unusual to find them with high oil and gas saturations. The problem is that the tiny pores restrict flow in the conventional sense to uneconomic rates. This is why a normal vertical well rarely flows any hydrocarbons from such rock, and why although the hydrocarbon content was well known, these rocks were not thought of as economically interesting until recently.

Horizontal Drilling and Multi-­-staged Fracture Stimulation

In order to expose much more reservoir rock to the wellbore, long horizontal drilling within the target zone has become necessary to allow the tight rock to produce enough hydrocarbons along the horizontal leg to be economic. However, this alone has not been enough. It is also necessary to stimulate the formation with numerous horizontally isolated fracture stimulations so as to break up the rock and create a connected fracture system along which hydrocarbons can be released and flow to the well bore. Wellbores are now routinely drilled up to one mile horizontally (two miles is achievable) and with 20-­-40 individual frac stages along their length (more have been achieved, but the efficacy has not been convincingly illustrated). All of this is very expensive technology to apply, which has required higher commodity prices to justify the effort. Higher commodity prices have driven the technology, which in turn has improved the technology so that it is now virtually a standard practice in North America.

High Initial Decline Rates That Change With Time

This is where the fundamental physical and economic differences arise in the unconventional tight play performance. The use of intense fracture stimulation creates a hybrid of two end members of hydrocarbon flow. At one end we have a conventional flow regime resulting from the liberation of hydrocarbons from very low porosity rock. This flow obeys more or less the same general rules of conventional flow as describe previously. The conventional behavior is completely overwhelmed by the flow related to the artificially created fracture systems due to the stimulation of the well. Fractures have almost no resistance to flow – think of them as little pipelines reaching well back into the formation. Accordingly, these fractures can deplete very quickly and while they result in tremendous early production rates, they demonstrate dramatic decline rates. The red lines on the chart above illustrate the basic shape of an unconventional production profile.

Since the modern unconventional tight well is a hybrid of conventional or near conventional flow and early fracture dominated flow, the well production performance is a blend of the two. This blend is fracture dominated early, and increasingly conventionally dominated later in life. How these two forms of flow interact over time, and how much later in life the conventional behavior takes over is a key topic with a lot of current uncertainty.

The Barnett Shale, arguably the first break-­-through shale play, was first horizontally drilled in 2003. This mere 10-­-year history compares with the 80 plus year history of many of North America’s principle conventional fields. The long-­-term behavior of tight play wells is uncertain. Also, each play is as different as the type of rock the play is developed in. There is a lot to learn on this front.

Statistical Reserves Performance

If there is one thing that is certain about tight plays, it is that the performance characteristic from one well to the next is uncertain. This results from the high variability of reservoir rock, fracture systems, drilling strategies, completion methods and completion efficiency. This has prompted a new approach to reserves estimation that is less reliant on reservoir engineering principles, and more reliant on statistical performance and “type curves”. This has prompted an array of new guidelines from organizations such as the Society of Petroleum Engineers, as well as from regulators.

The problem with the statistical approach is that a lot of wells need to be drilled before there are enough meaningful results to make for reliable statistics. In particular, the performance of wells later in their lives is necessarily an open question and is statistically vague for many of today’s hottest plays. New methods of fundamental reservoir analysis that are currently being developed are also challenged by the short histories of these plays.


The radical changes in drilling and completion practices that have revolutionized our thinking about energy security in North America have turned previously overlooked rocks into vast reservoirs. These reservoirs however, do not behave like the ones that have been exploited since the early part of the last century. How they do perform continues to be nothing less than a voyage of discovery, potentially fraught with yet to be discovered gems and hazards. One thing is sure; the economic performance of these new plays is different from the conventional plays of the past. A deeper dive into these economic parameters will be the subject of a future article.


Hubbert, M.K., 1956: Nuclear Energy and the Fossil Fuels, presented to the American Petroleum Institute.

Brackett, Will, Managing Editor Powell Barnett Shale Newsletter: A History and Overview of the Barnett Shale, available on

$90 Oil — Why All the Sad Faces?

pipe line transportation in crude oil refinery
 J Reader — Barchan Advisory Services Ltd. ©

Not very long ago the idea that oil would consistently trade between $90/bbl and $110/bbl would have been considered ridiculous. Now this is today’s price reality and it’s puzzling why there seems to be a pervasive discomfort among industry players – both participants and investors. This note addresses one part of the problem underlying these sentiments.

Since about the middle of 2003, the price of oil has been on a tear. Back then the de facto world crude benchmark had been more or less showing a price of US$30/bbl with some conviction. Canadians, who had been languishing with a 30%+ exchange discount to the US dollar, were able to see a better price in local currency that inspired sanctioning of several new oil sands projects. Then suddenly the dynamic around oil changed dramatically.

Oil is basically a global commodity. Since the value of a barrel of oil can be adjusted in a reasonably well-understood way for variables such as heaviness, impurities, and transportation, oil has stood out as a surrogate monetary equivalent. Subject to the adjustments mentioned above, one barrel is equivalent to another, its supply is generally scarce, and it is readily divisible. The standard identified for global purposes was the West Texas Intermediate (WTI) barrel that supplied the tremendous refinery and petrochemical centers on the tidewater of the Gulf of Mexico. A barrel anywhere in the world could be expressed in terms of WTI. Starting in the last half of 2003, WTI oil began an impressive ten-year rally to its current value in the mid-$90 range. What drove this impressive change in price, and what has it meant for the North American industry?

Two major factors have generated this result: increased demand from rapidly developing economies in Asia, and foreign exchange impacts. The former is thought to be well understood, but the latter is rarely appreciated and has profound impact on the industry. Implicit in our earlier discussion on the monetary standard characteristics of oil is the fact that international trade in oil has been typically quoted and transacted in US dollar currency. This convention has been until recently quite satisfactory, since the world has relied for many years on the greenback as its own monetary standard derived from the globe’s most profound economy. However, in the course of the last decade (and particularly after the crash of 2008) this foundational assumption has been severely compromised such that it is now unclear what the true value of oil is if it is priced in US dollars.

One way of looking at the problem is to investigate the trend of the US dollar/Chinese Yuan exchange rate. The following chart shows the ten-year index trend and indicates clearly that the US dollar has fallen 25% against the Yuan (and the trend is towards further devaluation). China, as a central growth player in the Asian story and a major consumer of oil is a reasonable marker to compare the change in value of the US dollar. While the Chinese worked hard to keep the value of the Yuan low with respect to the US currency, the practical forces of collapsing banks and ‘quantitative easing’ were overwhelming and such a fixed rate scheme had to collapse in the face of a weakening US economy. It isn’t shown here, but for those who are just too uncomfortable with a Chinese currency standard, similar trends can be observed in various global currencies.


Sticking for now with the Chinese example, it is interesting to observe how the ten-year price of oil has changed in that currency (see chart below). Basically, one can see that the price has a little more than doubled, where it has tripled for North Americans. Thus, on the basis of a simplistic analysis, we can conclude that in WTI terms, about half of the oil price increase is due to actual global demand growth, and the rest is due to the devaluation of the US dollar that WTI is measured in.


For those of us who were deeply in the business during the tough decade of the 1990’s and who watched with amazement the price growth of the last decade, we might be surprised to contemplate that the “value” of oil is only $60/bbl in the framework that we used to work in, and not the “apparent” $90/bbl of the NYMEX ticker!

This isn’t the whole problem for North American industry players either. A substantial portion of the heavy inputs to oil and gas investment, for example steel, pipe, and machinery is being sourced off-shore in the very economies that have driven up demand. This means that our input factors are also compromised by the falling exchange rate creating a economic squeeze play that is as impactful as it is difficult to observe directly.

Now, this is hardly a sophisticated analysis and certainly side-steps a lot of complicated global economic dynamics that influence the problem. If you stand back though, and consider the North American producer is faced with an oil price that clouds the value of the product, and a variety of capital cost inputs that are increasingly expensive in North American currency terms, maybe you can see why there is a glumness in the industry at prices that could hardly be imagined ten years ago.

 A Note on Sources:
The data used was extracted from the on-line FRED database of the Federal Reserve Bank of St. Louis ( The author also relied on the Pacific Exchange Rate Service provided by Dr. Werner Antweiler at the University of British Columbia ( for viewing and analyzing various trends.


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Copyright © Barchan Advisory Services Ltd. 2016


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