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A little on the Profitability of the Bakken(ND)

In the first part of this post I present an update on the profitability for Light Tight Oil (LTO) extraction in the Bakken (ND) as one big project.

This is followed with economic life cycle analysis for the average LTO well of the 2014, 2015 and 2016 vintages in the Bakken.

This analysis found that companies in aggregate continue to outspend net cash flows from operations and for 2017 this is now expected to total $2 – $3 Billion.

  • The strong growth and sustained high LTO extraction from the Bakken were facilitated by considerable amounts of debts. The growth in total debts outstanding (employed capital) continues to grow, albeit at a slower pace.
  • With oil prices sustained at present levels the total employed capital (primarily debt) constitutes severe obstacles for the profitability for the Bakken.
  • In a scenario where no wells were added post 2017 and the wellhead (at WH) price remained at $40/bo [~ $50/bo WTI] estimated losses for the project would be $20 – $22 Billion.
  • In a scenario where no wells were added post 2017 and the wellhead price remained at $60/bo [~ $70/bo WTI], the payout was reached after 7,5 years (in 2025) and the estimated return for the project becomes 3,5%.
  • With a sustained wellhead price at $74/bo [~ $84/bo WTI] post 2017, the payout was reached after 4,3 years (in 2022) and the estimated return becomes 7%.
    What makes the profitability for the Bakken challenging are the number of years front loaded with negative cash flows.
  • So far the recent years improvements in flow and Estimated Ultimate Recovery (EUR) have not entirely caught up with the decline in and the sustained lower oil price.
  • For the average 2016 vintage well it was estimated that a sustained oil price of $53/bo at WH [~ $63/bo WTI] would return 7%.

    Figure 01: The chart above shows the estimated rolling 12 months totals [black columns] net cash flows. The red area shows the estimated cumulative net cash flow since Jan-09 and per Jul-17. LOE, G&A and interest rates (effective, i.e. adjusted for tax effects) based on a weighted average from several companies’ SEC 10-K/Q filings. Taxes according to what has been in force. Price of oil, North Dakota Sweet (NDS) and realized gas price as reported by several companies.

In the Bakken(ND) and since January 2009 and per July 2017 an estimated $100 Billion has been used for manufacturing operational LTO wells and at end July 2017 an estimated $35 Billion were outstanding to be recovered from the estimated remaining proven developed producing (PDP) reserves.

At the most CAPEX for well manufacturing in the Bakken out spent cash flow from operations at an annual rate of $9 Billion. For the Bakken there has been two distinct CAPEX cycles, the first in 2011/2012 while the oil price remained high, followed by another in 2015 after the collapse in the oil price.

The second cycle may have been rationalized by several factors like an expected rebound in the oil price, which OPEC (primarily its Middle East members) helped derail through their rapid increase in oil supplies starting in early 2015 in an (believed) effort to fight for market share. The second cycle may also have been rationalized by the incentive structure for management of LTO companies in which these were rewarded by volume growth over profitability.

Incurred costs for drilled, uncompleted wells (DUCs) and salt water disposal wells (SWDs) are not included. Directors cut for September 2017 listed 889 wells waiting for completion. Costs from any heavy and costly well maintenance/interventions are not included.

The DUCs represents $2,2 – $2,7 Billion in capital employed.

For the Bakken as one big project and the life cycle analysis the gross interest costs of 6% were reduced by 35% to reflect corporate tax effects.

Effects from hedges and from bankruptcy proceedings (debt restructuring) are not included.

Any arbitrage from the realized oil price adjusted for wellhead price, transport costs and any tax effects from this arbitrage are not included.

Some companies are now recirculating primarily borrowed money (at some interest) from the net operating cash flow and injecting additional capital  to continue the manufacturing of new wells.

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Written by Rune Likvern

Sunday, 8 October, 2017 at 19:26

The Bakken, a little about EUR and R/P

In this post I present some of the methods I have used to get estimates based on actual NDIC data on the Estimated Ultimate Recovery (EUR) for wells in the Bakken North Dakota.

The Bakken is here being treated as one big entity. As the Bakken shales [for geological reasons] are not ubiquitous there will be differences amongst pools, formations and companies.

One metric to evaluate the efficiency of a Light Tight Oil (LTO) well and a large population of wells are looking at developments in the Reserves over Production (R/P) ratio.

The R/P ratio is a snapshot that gives a theoretical duration, normally expressed in years, the production level for one particular year can be sustained at with the reserves in production at the end of that year.

Further, as LTO wells decline steeply and a big portion of the total extraction has come/comes from wells started less than 2 years ago, this dominates the Reserves/Production (R/P) ratio. The flow from a big population of high flowing wells in steep decline results in a low R/P ratio (and vice versa).

The R/P metric says nothing about extraction in absolute terms, which is another metric that needs to be brought into consideration in order to obtain a more complete picture of expected developments.

Development in Well Totals by Categories

Figure 1: In the chart above the about 10,000 wells with 12 months of flow or more [started as of Jan-08 - Jul-15] has been split into 5 categories [ref the legend] and the average monthly flow versus total [for the average] has been plotted for each category. Cut off has been made after 72 months (6 years) as the declining number of wells over time makes the calculations susceptible to noise like from refracking in the tail and because of a declining well population. This method makes it possible to identify the EUR trajectories for each category of wells. The average well in the Bakken now follows a trajectory 2-4% below the green line [wells above 75 kbo and less than 100 kbo after the first 12 months of flow]. The colored dotted lines [sloping upwards to the right] connects each category after the first 12, 24, 36, etc months of flow.

Figure 1: In the chart above the about 10,000 wells with 12 months of flow or more [started as of Jan-08 – Jul-15] has been split into 5 categories [ref the legend] and the average monthly flow versus total [for the average] has been plotted for each category. Cut off has been made after 72 months (6 years) as the declining number of wells over time makes the calculations susceptible to noise like from refracking in the tail and because of a declining well population.
This method makes it possible to identify the EUR trajectories for each category of wells. The average well in the Bakken now follows a trajectory 2-4% below the green line [wells above 75 kbo and less than 100 kbo after the first 12 months of flow].
The colored dotted lines [sloping upwards to the right] connects each category after the first 12, 24, 36, etc months of flow.

The average Bakken well is now estimated to reach a EUR of 320 kbo [kbo; kilo barrels oil = 1,000 bo]. Based on this, the average well has an R/P of 2.7 after its first year of flow, which suggests that about 27% of its EUR is recovered during its first year of flow.

Estimates done by others based on actual NDIC data puts now the EUR for the average Bakken well slightly below 300 kbo.

As from what point the wells reach the end of their economic life, educated guesses now spans from 10 bo/d (0.3 kbo/Month) to 25 bo/d (0.75 kbo/Month).

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Written by Rune Likvern

Sunday, 21 August, 2016 at 20:13

Oil, Interest Rates and Debt

At first glance it is hard to see how oil, interest rates and debt are connected. Two of them are human constructs while oil (fossil sunlight), a gift from Mother Nature, took tens of millions of years to process. Oil is an endowment extracted from a confined underground stock and is now the most dense and versatile energy source known to man.

Figure 1: Chart that shows the development of [extraction] cost of oil and interest rates (US 10 Year Treasuries) has developed since 2000 and a likely trajectory for oil extraction costs.

Figure 1: Chart that shows the development of [extraction] cost of oil and interest rates (US 10 Year Treasuries) has developed since 2000 and a likely trajectory for oil extraction costs.

Both lines are SIGNALS, and most likely plan their future based on only one of them.

The 10 Year Treasury (or similar) rate is the reference used for amongst other things to set interest rate for mortgages. Most now, aware of it or not, base their future plans on the expectations to developments of the 10 Year Treasury.

What is now playing out in the oil market may be described as below;

Low interest rates [stimulates debt growth] => Pulls demand forward => Oversupply => Deflation

How will the interest rate develop in the future?

This is important as the present huge global debt overhang weighs heavily in the consumers’ balance sheets and their affordability for costlier oil. It is also important for oil companies’ long term planning to bring costlier oil to the market.

A lasting, low rate makes higher debt loads manageable. Interest rates works both sides of the demand/supply equation.

A higher interest rate will have serious implications for highly leveraged consumers and oil companies.

The dynamics may be described as below:

Higher interest rate => lowers demand => downward pressure on price [deflation] => makes it harder for [highly leveraged] consumers/oil companies to service their debt overhang => lowers investments to develop costlier supplies

At some point in time the present oil supply overhang will come to an end. This will become reflected in a higher price.

The timing of these events creates uncertainties and the agile and financial strong oil companies will sweat out a lasting low oil price.

Few are aware of that the costs of accessing our real capital (like oil) that runs our economies are rapidly increasing.

What is different this time is that the oil price may remain lower for longer than the estimated full cycle break even costs for new developments.

The suggested path for costs is believed in the near term to come down as oil service companies have reduced their prices to shoulder the burden from the recent price collapse. Over time, the capacities of the service companies will become aligned with the demand for their services and products. At some point, as the oil price recovers and investments pick up, the market mechanisms will bring the prices from the service companies up as the service companies also need to make a profit to stay in business.

In figures 4 and 5 are shown how the combination of lower interest rates and a lasting, high oil price encouraged the oil companies to rapidly take on more debt to develop costlier oil on the expectations that consumers had remaining ability to take on more debt/credit to pay for this, thus allowing the oil companies to retire their debts.

The oil companies’ behavior in the recent decade is reminiscent of group think. Few expected the oil price to collapse, though the oil industry itself repeatedly point out the cyclical nature of the oil price.

The aggregate of developments (primarily driven by an amazing growth in the extraction of light tight oil [LTO]) gradually resulted in a supply overhang that made the oil price collapse.

The costs of extracting real capital, like oil, has been rapidly increasing, yet we are making decisions for the future as if it were decreasing, based on the price of capital (money). This is a short term phenomenon that will last until supply and demand become balanced.

The present situation with an apparent oil glut and low prices is a temporary false signal.

This may also be the case with the low interest rates.

The near future will reveal how the competition for available funds to service a still growing huge global debt overhang fare towards the need to fund developments of costlier oil.

Can an increasingly leveraged global economy handle both higher oil prices and interest rates and still remain on its growth trajectory?

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Norwegian Crude Oil Reserves And Extraction per 2015

In this post I present actual Norwegian crude oil extraction and status on the development in discoveries and reserves and what this has now resulted in for expectations for future Norwegian crude oil extraction.

This post is also an update of an earlier post about Norwegian crude oil reserves and production per 2014.

Norwegian crude oil extraction peaked in 2001 at 3.12 Million barrels per day (Mb/d) and in 2015 it was 1.57 Mb/d, growing from 1.51 Mb/d in 2014.

The Norwegian Petroleum Directorate’s (NPD) recent forecast expects crude oil extraction from the Norwegian Continental Shelf (NCS) will decline to 1.53 Mb/d in 2016.

Figure 01: The chart shows the historical extraction (production) of crude oil (by discovery/field) for the Norwegian Continental Shelf (NCS) with data from the Norwegian Petroleum Directorate (NPD) for the years 1970 - 2015. The chart also includes my forecast for crude oil extraction from discoveries/fields towards 2030 based on reviews on individual fields, NPD’s estimates of remaining recoverable reserves, the development/forecast for the R/P ratio as of end 2015. Further, the chart shows a forecast for total crude oil extraction from sanctioned discoveries/fields (green area, refer also figure 02) and expected contribution from Johan Sverdrup (blue area) [at end 2015 estimated at 1.76 Gb; [Gb, Giga (Billion) barrels, refer also figure 06] and this development phase is now scheduled to start flowing in late 2019.

Figure 01: The chart shows the historical extraction (production) of crude oil (by discovery/field) for the Norwegian Continental Shelf (NCS) with data from the Norwegian Petroleum Directorate (NPD) for the years 1970 – 2015. The chart also includes my forecast for crude oil extraction from discoveries/fields towards 2030 based on reviews on individual fields, NPD’s estimates of remaining recoverable reserves, the development/forecast for the R/P ratio as of end 2015.
Further, the chart shows a forecast for total crude oil extraction from sanctioned discoveries/fields (green area, refer also figure 02) and expected contribution from Johan Sverdrup (blue area) [at end 2015 estimated at 1.76 Gb; [Gb, Giga (Billion) barrels, refer also figure 06] and this development phase is now scheduled to start flowing in late 2019.

Sanctioned Developments in Figure 01 represents the total contributions from 7 sanctioned developments of discoveries now scheduled to start to flow between 2016 and 2019.

My forecast for 2016 is 1.50 Mb/d with crude oil from the NCS.

My forecast shown in figure 01 includes all sanctioned developments and not discoveries (refer also figure 08) and contingent resources in the fields. The forecast is subject to revisions as the reserve base becomes revised (as discoveries pass the commercial hurdles) which likely will fatten the tail of the presented forecast post 2020.

My forecast assumes some reserve growth, but does not include the effects from fields/discoveries being plugged and abandoned as these reach the end of their economic life.

Discoveries sanctioned for development and Johan Sverdrup (with an expected start up late 2019) is expected to slow down the decline in Norwegian crude oil extraction.

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Bakken(ND) Light Tight Oil – Update with Sep – 15 NDIC Data

After years of following developments in extraction of light tight oil (LTO) in the Bakken, the oil price, studying actual well production data from the North Dakota Industrial Commission (NDIC) and the SEC 10-Q/Ks filings for several companies heavily exposed to the Bakken, a quote from Shakespeare’s Macbeth comes to the fore of my mind:

All causes shall give way: I am in blood

Stepp’d in so far that, should I wade no more,

Returning were as tedious as go o’er:

                                              (Macbeth: Act III, Scene IV)

For me the Macbeth quote very much sums up the predicament many Bakken LTO operators now find themselves in.

Figure 01: The above chart shows developments by vintage in LTO extraction from the Middle Bakken/ Three Forks/Sanish formations in Bakken (ND) as of January 2008 and of September 2015 [right hand scale]. The color grading shows extraction by month. Development in the oil price (WTI) black line is shown versus the left hand scale.

Figure 01: The above chart shows developments by vintage in LTO extraction from the Middle Bakken/ Three Forks/Sanish formations in Bakken (ND) as of January 2008 and of September 2015 [right hand scale].
The color grading shows extraction by month.
Development in the oil price (WTI) black line is shown versus the left hand scale.

What this study/update present:

  • With the decline in the oil price the average well as from the 2012 vintage will struggle to reach payout and become profitable.
    (The oil price decline reduces the portion of the more recent wells that are on trajectories to reach payout and become profitable.)
  • The 2015 vintage follows the 2014 vintage closely, suggesting that around 20% of the wells of 2015 vintage are on a trajectory to reach payout and become profitable.
  • The underlying decline from the legacy wells is strong. The extraction from all the wells started between Jan 2008 and Dec 2014 declined by close to 440 kb (or about 41%) from Dec 2014 to Sep 2015.
  • Some of the early wells (2008 vintage) have been restimulated (refracked) and the effects are short lived and the economics of this looks questionable, at best.
  • A near steep decline in LTO extraction from the Bakken is baked into the cake due to the financial dynamics created by a lasting low oil price.
  • An average of around 136 wells/month were added so far in 2015 while extraction declined close to 60 kb/d, suggesting 140 – 150 wells needs to be added each month to sustain present extraction levels.

Studying the SEC 10-K/Qs for several of the companies that are heavily weighted in the Bakken shows that natural gas and NGLs (Natural Gas Liquids) are weighing down the financial results for many companies.

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Written by Rune Likvern

Monday, 30 November, 2015 at 21:49

Are the Light Tight Oil (LTO) Companies trying to outsmart Mother Nature with their Financial Balance Sheets?

In this post I present what I found from applying R/P (Reserves divided by [annual] Production) ratios for Light Tight Oil (LTO) for 3 big companies in Bakken/Three Forks/Sanish.

The companies are; Continental Resources, Oasis Petroleum and Whiting Petroleum, which operated 28% of total LTO extraction in the Bakken(ND) in December 2014.

  • Undertaking oil and gas reserves assessments are just as much an art as a science.

From previous work with LTO from Bakken I kept track of the R/P ratio for wells/portfolios and generally found it was in the range of 3 – 4 after their first year of flow. This suggested that 25 – 35% of the wells’ Estimated Ultimate Recovery (EUR) was extracted in their first year of flow.

This made sense as extraction (production) from LTO wells are heavily front end loaded and have steep initial declines.

Examining some big Bakken companies SEC 10-K (SEC; Securities and Exchange Commission) filings for 2014 I noticed that these had R/P ratios for Proven Developed Reserves (PDP) that ranged from 7 – 9.

(Refer to the end of this post for more detailed explanations/definitions of PDP and PUD)

That did not make sense and R/P ratios give away powerful and very valuable information about likely future extraction trajectories.

About 50% of the companies’ total LTO extraction (flow) in Dec 2014 in Bakken (ND) were from wells started in 2014. In other words, the flow was dominated by “young” wells which decline rapidly. Therefore, whatever flow data (monthly, quarterly) that was annualized it should be expected a R/P ratio for total extraction around 4 for 2014.

What I present is how PDP, extraction data and R/P data derived from the 3 companies SEC 10-K statements compares to what was derived from actual data. Further, what actual data now is projecting for EUR for the average well for these companies.

Figure 1: The chart above shows developments in average well first year LTO totals (productivity) for some companies and by vintage. The colored columns for 2013 and 2015 show projected financial performance based on average well first year LTO totals. For 2013 the chart is based on: WTI at $98/b and a type well at $10M was found to have a 0% return with a total first year LTO flow at about  50 kb.  For 2015 the chart is based on: WTI at $60/b and a type well at $8M was found to have a 0% return with a total first year LTO flow at about 90 kb.  The chart illustrates that the well productivity has been on an upward trend. So far the productivity improvements and cost reductions have not fully compensated for the effects from a much lower oil price.  The profitability equation of the type well was solved for the equivalent total first year flow for various oil prices and costs on a point forward basis. A lower oil price makes the red columns “push” the other ones upwards (moves the profitability bands upwards). Wells of 2015 vintage (pre May) are on a trajectory close to those of the 2014 vintage. kb,  kilo barrels = 1,000 barrels

Figure 1: The chart above shows developments in average well first year LTO totals (productivity) for some companies and by vintage. The colored columns for 2013 and 2015 show projected financial performance based on average well first year LTO totals.
For 2013 the chart is based on: WTI at $98/b and a type well at $10M was found to have a 0% return with a total first year LTO flow at about 50 kb.
For 2015 the chart is based on: WTI at $60/b and a type well at $8M was found to have a 0% return with a total first year LTO flow at about 90 kb.
The chart illustrates that the well productivity has been on an upward trend. So far the productivity improvements and cost reductions have not fully compensated for the effects from a much lower oil price.
The profitability equation of the type well was solved for the equivalent total first year flow for various oil prices and costs on a point forward basis.
A lower oil price makes the red columns “push” the other ones upwards (moves the profitability bands upwards).
Wells of 2015 vintage (per May) are on a trajectory close to those of the 2014 vintage.
kb, kilo barrels = 1,000 barrels

LTO in Bakken will now generally work profitably with an oil price (WTI) above $80/b.

The willingness of several companies to sell more debt (obtain more credit), assets and equity to continue to manufacture LTO wells which estimates showed were not commercially viable have had many analysts puzzled.

Something was likely overlooked, and chances are that this is related to EUR driven incentives to expand assets/equity on the companies’ balance sheets (or “book to model”).

As companies drill wells and puts these in operation (production), it allows them to book reserves on the balance sheets. And reserves are the biggest portion of the LTO companies’ balance sheets.

The rush to use credit/debt to drill what likely would become unprofitable wells (applying project economics) with a lasting, low oil price appears driven by some perverse incentive to grow booked reserves to grow assets and thus equity on the companies’ balance sheets, overriding outlooks for poor profitability. High equity on the balance sheets allows for more debt.

Looking at actual, hard well data (from NDIC; North Dakota Industrial Commission) this strategy will at some point have to face up to the realities of physics and Nature. And physics and Nature do NOT negotiate.

  • Using actual data for LTO wells strongly suggests that the PDP (and thus PUD) estimates in companies’ SEC 10-K filings for 2014 are grossly inflated. If so, this has inflated the assets/equity numbers on the companies’ balance sheets.
  • The findings from this study suggest that the massive drilling activity funded by growing debt, was likely motivated by balance sheets expansions of assets, and thus the equity from inflated EUR numbers (“book to model”) which made room to take on more debt.
  • An inflated balance sheet that allows for a debt load above the carrying capacities of the real underlying collateral, will at some point in time turn against their creators and call for revisions of future plans and expectations.
  • It will be interesting to see how the LTO companies’ balance sheets and their profitability respond as it become Mother Nature’s turn with the bat.

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Written by Rune Likvern

Monday, 3 August, 2015 at 10:33

Is the Red Queen outrunning Bakken LTO extraction?

This post is an update on LTO extraction in Bakken based upon published data from the North Dakota Industrial Commission (NDIC) as per January 2015.

This post also presents a closer look at developments in LTO extracted from the three of the four counties that presently dominates LTO extraction; McKenzie, Mountrail and Williams.

With an oil price below $50/Bbl (WTI) the companies involved in extraction of LTO in Bakken faces two financial challenges;

  1. The decline in the cash flow from operations reduces funding capacities for manufacturing new wells. A lower oil price also lowers the value of the companies’ assets and borrowing capacities.
  2. The “average” well with around 90 kb [90,000 Bbls] of flow in its first year is estimated to have an undiscounted point forward break even (that is a nominal break even with 0% return for the well) at around $65/Bbl (WTI). The break even price increases with increases in the return requirement.


In short, LTO extraction at present prices
($45/Bbl, WTI) makes little commercial sense!

Figure 01: The chart above shows development in Light Tight Oil (LTO) extraction from January 2009 and as of January 2015 in Bakken North Dakota [green area, right hand scale]. The top black line is the price of Western Texas Intermediate (WTI), red middle line the Bakken LTO price (sweet) as published by the Director for NDIC and bottom orange line the spread between WTI and Bakken LTO wellhead all left hand scale.

Figure 01: The chart above shows development in Light Tight Oil (LTO) extraction from January 2009 and as of January 2015 in Bakken North Dakota [green area, right hand scale]. The top black line is the price of Western Texas Intermediate (WTI), red middle line the Bakken LTO price (sweet) as published by the Director for NDIC and bottom orange line the spread between WTI and Bakken LTO wellhead all left hand scale.

From December 2014 to January 2015 LTO extraction from Bakken(ND) declined from 1.16 Mb/d to 1.13 Mb/d.

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