FRACTIONAL FLOW

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The Bakken, a little about EUR and R/P

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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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The Bakken LTO extraction in Retrospect and a Forecast of Near Future Developments

In retrospect, it becomes easier to understand the amazing growth and resilience of Light Tight Oil (LTO) extraction from Bakken (and other US tight oil plays) if the effects from the use of huge amounts of debts (including assets and equities sales) is put into this context.

Debt leverage together with a high oil price are what stimulated the US LTO extraction for some time to appear as something like a license to print money.

Now, and as long present low oil prices persist, the LTO companies are in financial straitjackets.

  • It was high CAPEX in 2015 from external funding, primarily debt and assets/equities sales, that created the impression of LTO’s resilience to lower oil prices (ref also figure 2).
    Actual data show that so far there has been some improvements in well productivities [cumulative versus time]. However, these improvements by themselves do not fully explain the apparent resilience of LTO extraction to lower oil prices.
  • NONE of the wells now added in the Bakken are on trajectories to become profitable at present prices (ref also figure 3).
    The average well now needs about $80/bo at the wellhead to be on a profitable trajectory.
    (The average spread between WTI and North Dakota Sweet has been and is above $10/bo.)
  • As far as actual data from NDIC on well productivity (EUR trajectories) provide any guidance it is not expected that well manufacturing will pick up in a meaningful way before the oil price moves and remains above $60/bo @ WH.

Writing down the drilling cost and rebasing profitability from completion costs [for DUCs, Drilled UnCompleted wells] does not change this fact.

  • The decline in the LTO extraction will (all things equal) relentlessly erode future funding capacities for drilling and completion [well manufacturing].
  • It is now all about the net cash flow from operations, debt service and retirement of debts [clearing the bond hurdles]. Debt management and debt restructuring will remain on top of the agenda for management of LTO companies. It should be expected that the management of these companies will do everything in their powers to clear the bond hurdles and keep their companies out of bankruptcy.
  • For 2016 well additions in the Bakken will fall below the threshold that allows to fully replace extracted reserves.
    In the industry this is referred to as the Reserves Replacement Ratio (RRR).
    For the Bakken the RRR for 2016 is now expected to be below 50%.
    (This lowers the collateral of the LTO companies and their debt carrying capacities.)

At present prices several companies cannot both retire their debts according to present redemption profiles and manufacture a lot of wells. This is why it is suspected that halting all drilling (where feasible [i.e. Contracts without stiff penalties for cancellation]) and deferring completions have become a necessity born out of the requirements for debt management.

This analysis presents:

  • A forecast on total LTO extraction for Bakken (ND, MB/TF) towards the end of 2017.
  • A closer look at a generic LTO company in Bakken and its near future challenges with clearing the bond hurdles.
    (The generic LTO company is based on [weighted] financial data from several, primarily Bakken invested companies’ Security and Exchange Commissions (SEC) 10-K/Q filings for 2015).
    To keep the focus on the (debt) dynamics in play, The Financial Red Queen, I opted to use a generic company. This is also done to play down discussions about specific companies.
  • The important message to drive home is how declining cash flow from operations, the big debt overhang and clearing the bond hurdles will constrain many LTO companies’ funding (CAPEX) for well manufacturing [drilling and/or completion] as long as oil prices remain below $60/bo @WH (or about $70/bo, WTI).

Figure 1: The chart above show actual LTO extraction from Bakken (ND, MB/TF) [green area], the funding constrained forecast towards end 2017 [grey area] and how LTO extraction is forecast to develop if no producing wells were added post Jan-16 [black dotted line].

Figure 1: The chart above show actual LTO extraction from Bakken (ND, MB/TF) [green area], the funding constrained forecast towards end 2017 [grey area] and how LTO extraction is forecast to develop if no producing wells were added post Jan-16 [black dotted line].

The companies operating in Bakken come in many sizes and business models and some of the majors (or subsidiaries thereof) likely have bigger financial muscles, lower debt costs (interest rates) and may have somewhat lower specific costs due to scale of operations.

  • With sustained low oil prices, the servicing of total debt has been and will be the power that forces companies deep in debt and heavily exposed to LTO into bankruptcies and causes losses on creditors and become the real driver behind the steep decline in LTO extraction.

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Written by Rune Likvern

Wednesday, 6 April, 2016 at 21:51

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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The Oil Price – Some (Mar-16) Observations and Thoughts

In this post I present some selected parameters I monitor which may help understand near term (2-3 years) oil price movements and levels.

It has been my understanding for some time that the formulations of fiscal and monetary policies also affects the commodities markets. Changes to total global debt has and will continue to affect consumers’/societies’ affordability and thus also the price formation of oil.

I have earlier asserted;

Any forecasts of oil (and gas) demand/supplies and oil price trajectories are NOT very helpful if they do not incorporate forecasts for changes to total global credit/debt, interest rates and developments to consumers’/societies’ affordability.

  • The permanence of the global supply overhang could be prolonged if consumption/demand developments soften/weakens and it is not possible to rule out a near term decline.
  • Recent demand/consumption data for total US petroleum products supplied show signs of saturation which provides headwinds for any upwards movements in the oil price.
  • While prices were high many oil companies went deeper into debt in a bid to increase production of costlier oil. Many responded to the price collapse with attempts to sustain/grow production in efforts to moderate cash flow declines and thus ease debt service.
  • If the forward [futures] curve moves from a present weak contango (ref also figure 02) to backwardation, this would erode support for the oil price.
  • Some suggest that growth from India will take over as China’s growth slows.
    Looking at the data from the Bank for International Settlements (BIS) there is nothing there that now suggests India (refer also figure 05) has started to accelerate its debt expansion. The Indian Rupee has depreciated versus the US dollar, thus offsetting some of the stimulative consumption effects from a lower oil price.

The recent weeks oil price volatility has likely been influenced by several factors like short squeezes, rumors and fluid sentiments.

Near term factors that likely will move the oil price higher.

  • Continued growth in debt primarily in China and the US. {This will go on until it cannot!}
  • Another round with concerted efforts of the major central banks with lower interest rates and quantitative easing.

And/or

  • A tightening in the global oil demand/supply balance from whatever reasons.

I also believe that D E M A N D (consumption) developments now are more important than widely recognized and that demand/consumption developments will play a major factor in as from when oil prices will regain support to move to a sustainable higher level.

I now hold it 90% probable that the oil price will enter a new leg down, and that the low in January 2016 could be taken out.

Recently the total US petroleum demand growth had two components

  1. Growth in consumption, mainly driven by the collapse of the oil price
  2. Noticeable growth in petroleum stocks (primarily crude oil) since late 2014 driven by a favorable contango.

The combined effects from these grew annualized US petroleum demand by 1.3 Mb/d relative to January 2014 (ref also figure 01). US consumption growth has now stalled, which may suggest saturation from the lower oil price is about to be reached.

Figure 01: The chart above shows development in annualized [52 weeks moving averages] US total petroleum consumption [blue line] and storage build [red line] both rh scale. The black line, lh scale, shows development in the oil price (WTI). Consumption and storage developments are relative to Janaury 2014 (baseline). NOTE, changes in consumption and stocks are stacked, thus the red line also shows total annualized changes in demand.

Figure 01: The chart above shows development in annualized [52 weeks moving averages] US total petroleum consumption [blue line] and storage build [red line] both rh scale. The black line, lh scale, shows development in the oil price (WTI). Consumption and storage developments are relative to Janaury 2014 (baseline).
NOTE, changes in consumption and stocks are stacked, thus the red line also shows total annualized changes in demand.

In the last 6 months total US petroleum consumption developments have stalled and there are some relative changes amongst the products (ref below).

A weakened contango (ref also figure 02) will likely reduce demand for storage.

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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

Status of Norwegian Natural Gas at end of 2014 and Forecasts towards 2025

In this post I present actual Norwegian natural gas production, status on reserves, the development in discoveries and what this results for Norwegian Petroleum Directorate (NPD) and my expectations for the future delivery potential for Norwegian natural gas.

Norway, after Russia, has been and is the EU’s second biggest supplier of natural gas.

Included is also a brief look at developments in actual consumption and production of natural gas in the EU 28 (the 28 members of the European Union).

  • NPD revised down their band for future delivery potential by about 10 Gcm/a (Bcm/a) and moved the start of decline one year forward relative to their forecast last year.
  • I now expect the Norwegian delivery potential for natural gas relative to 2014/2015 to decline by more than 40% by 2025.
  • Europe will increasingly have to rely on natural gas imports from more distant sources and should by now have implemented policies for the role natural gas will have in its future energy mix.

This post is an update to my post in 2014 looking at the status as of end 2013.

Figure 1: The chart above shows development in natural gas exports from production installations on the Norwegian Continental Shelf (NCS) as reported by the Norwegian Petroleum Directorate (NPD) from 1996 to 2014 and with my forecast for delivery potential towards 2025. The chart also shows the NPD forecasts; green line upper projection, orange line lower projection. NPD’s central projection is in about the middle of the green and orange lines. The black dotted line is the forecast from the International Energy Agency’s World Energy Outlook 2012 (IEA WEO 2012). Numbers are believed to be gross exports from the production installations and thus not adjusted for “shrinkage” from Natural Gas Liquids (NGL) extraction, primarily at Kollsnes and Kårstø. The NGL extraction reduces total sales gas volumes with around 4% relative to what is exported from the producing installations. Numbers in Gcm, Giga cubic meters (Gcm = Bcm; Billion cubic meters)

Figure 1: The chart above shows development in natural gas exports from production installations on the Norwegian Continental Shelf (NCS) as reported by the Norwegian Petroleum Directorate (NPD) from 1996 to 2014 and with my forecast for delivery potential towards 2025.
The chart also shows the NPD forecasts; green line upper projection, orange line lower projection. NPD’s central projection is in about the middle of the green and orange lines.
The black dotted line is the forecast from the International Energy Agency’s World Energy Outlook 2012 (IEA WEO 2012).
Numbers are believed to be gross exports from the production installations and thus not adjusted for “shrinkage” from Natural Gas Liquids (NGL) extraction, primarily at Kollsnes and Kårstø. The NGL extraction reduces total sales gas volumes with around 4% relative to what is exported from the producing installations.
Numbers in Gcm, Giga cubic meters (Gcm = Bcm; Billion cubic meters)

My forecast  and NPD’s forecast at end 2014 are basically identical towards the end of this decade, but differs about the timing for the start of the decline and how steep this will become as from early next decade. My forecast is also tested versus the Reserves over Production (R/P) ratio as of end 2014, refer also figure 2.

At end 2014 the NPD projection of Norwegian natural gas supply potential towards 2025 was revised down.

NPD’s central projection is in about the middle of the green and orange lines. Note the span of uncertainties in the NPD’s forecast.

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