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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.

NOTE: Actual data used for this analysis are all from North Dakota Industrial Commission (NDIC). For wells on confidential list, data on runs (oil sold) were used as proxies for extraction.

Well production data for the Bakken, North Dakota: Monthly Production Report Index

Formation data from: Bakken Horizontal Wells By Producing Zone

The assembled well production data have been juxtaposed by formation and kindly made available by the excellent work of Enno Peters’.

Going forward, it is expected that the companies CAPEX funding primarily will come from operational cash flows (as companies strive to become cash flow neutral) which now monthly could fund the manufacturing of 50 – 60 wells [from spud to flow] which will slow the decline in extraction from the growing number of legacy wells.

Using operational cash flow for well manufacturing from a declining production while specific debt service and operational costs grow, sets up some vicious feedback loops that with a lasting, low oil price will force the companies to continuously reduce their CAPEX and OPEX.

A lasting, low oil price while production declines will, by default, for most companies result in an increased (debt) leverage.

The dynamics in play results from years of debt growth in a bid to grow LTO extraction, betting on oil prices would remain high. Meet the Financial Red Queen, who is harsher than her physical sister.

Figure 02: The chart above shows an estimate in development of cumulative net cash flows post CAPEX for manufacturing LTO wells in the Bakken (ND) as of January 2009 and as of September 2015 (red area and rh scale) and estimated monthly net cash flows post CAPEX (black columns and lh scale). The assumptions for the chart are WTI oil price (realized price which is netted back to the wellhead), average well costs starting at $8 Million in January 2009 and growing to $10 Million as of January 2011 and $9 Million as of January 2013 with a decline towards $8 Million as of January 2015. All costs assumed to incur as the wells were reported starting to flow (this creates some backlog for cumulative costs as these are incurred continuously during the manufacturing of the wells) and the estimates do not include costs of non- flowing and dry wells, water disposal wells, exploration wells, seismic surveys, acreage acquisitions etc. Economic assumptions; royalties of 16%, production tax of 5%, an extraction tax of 6.5%, OPEX at $5/Bbl, transport (from wellhead to refinery) $12/Bbl and a weighted interest of 6% on debt (before any corporate tax effects, which now adds around $3/Bbl in financial costs) and income from natural gas/NGPL sales (which now and on average grosses around 1.3 Mcf/Bbl). Estimates do not include the effects of hedging. Estimates do not include investments in processing/transport facilities and externalities like road upkeep, etc. The purpose with the estimates presented in the chart is to present an approximation of net cash flows and development in total use of primarily debt for manufacturing of LTO wells. The chart serves as a proxy for estimates of the aggregate cash flow for all oil companies in Bakken(ND).

Figure 02: The chart above shows an estimate in development of cumulative net cash flows post CAPEX for manufacturing LTO wells in the Bakken (ND) as of January 2009 and as of September 2015 (red area and rh scale) and estimated monthly net cash flows post CAPEX (black columns and lh scale).
The assumptions for the chart are WTI oil price (realized price which is netted back to the wellhead), average well costs starting at $8 Million in January 2009 and growing to $10 Million as of January 2011 and $9 Million as of January 2013 with a decline towards $8 Million as of January 2015. All costs assumed to incur as the wells were reported starting to flow (this creates some backlog for cumulative costs as these are incurred continuously during the manufacturing of the wells) and the estimates do not include costs of non- flowing and dry wells, water disposal wells, exploration wells, seismic surveys, acreage acquisitions etc.
Economic assumptions; royalties of 16%, production tax of 5%, an extraction tax of 6.5%, OPEX at $5/Bbl, transport (from wellhead to refinery) $12/Bbl and a weighted interest of 6% on debt (before any corporate tax effects, which now adds around $3/Bbl in financial costs) and income from natural gas/NGPL sales (which now and on average grosses around 1.3 Mcf/Bbl).
Estimates do not include the effects of hedging.
Estimates do not include investments in processing/transport facilities and externalities like road upkeep, etc. The purpose with the estimates presented in the chart is to present an approximation of net cash flows and development in total use of primarily debt for manufacturing of LTO wells.
The chart serves as a proxy for estimates of the aggregate cash flow for all oil companies in Bakken(ND).

September 15 had a higher oil price than August 15 resulting in some improved cash flows.

Most companies in Bakken were operational cash flow negative during the period with high oil prices, bridging the gap by assuming more debt.

Most companies decided to fight the decline in the oil price (betting on it was temporary) and has so far in 2015 increased their aggregate debt with an estimated $6 Billion to sustain extraction levels.

As the oil price remained low this resulted in a worrisome increase in several companies leverage that will confine their abilities for future well manufacturing.

Several companies’ credit lines were up for revision earlier this fall and resulted in few minor downward adjustments. The important part of these revisions are to be found with any revisions to the covenants [which is not available in the public domain].

These covenants may describe metrics the companies agreed to comply to, like the ratio of debt services to cash flow, equity thresholds [debt/equity ratios] or similar.

Figure 03: The chart show developments in the EUR trajectories for the average LTO well by vintage in the Bakken(ND).

Figure 03: The chart show developments in the EUR trajectories for the average LTO well by vintage in the Bakken(ND).

Figure 04: The above chart shows estimates on cumulative net backs at the wellhead for the average Bakken LTO well by vintage.

Figure 04: The above chart shows estimates on cumulative net backs at the wellhead for the average Bakken LTO well by vintage.

Improved well productivity (ref figures 03 and 05) has partially offset the decline in the oil price resulting that the payout (recovery of the nominal investment) and profitability as from the 2012 vintage will struggle.

The average well of the 2015 vintage is now on net back trajectory that is poorer than the 2009 vintage despite improvements in productivity and lower costs. This is the workings of the lower oil price.

LTO extraction is heavily front end loaded and the wells profitability is therefore very much influenced by the oil price during their first 3 – 4 years of operation.

A rule of thumb in the oil field says that for any project to become profitable it should reach payout after 4 – 5 years from start of flow.

With reference to the chart of the normal distribution by vintage (ref also figure 05) it means that a lower portion of the wells as of the 2012 vintage are on profitable trajectories.

The early vintages became buoyed by the high oil price. The vintages as from 2012 have experienced severe headwinds from the lower oil price.

Figure 05: The above chart shows the normal distribution of productivity of the wells by vintage expressed by 12 first months totals for Middle Bakken/Three Forks/Sanish. How to read the chart: The lines show the normal distribution for all studied wells started in 2008 - 2014, ref also the table in the upper left of the chart. 50 % of the 2014 wells have a total first 12 months flow flow of more than 86 kb while 43% were above the average of 92 kb. About 20% of the 2014 wells have a total first 12 months flow of 125 kb or more. kb, kilo barrels = 1,000 barrels

Figure 05: The above chart shows the normal distribution of productivity of the wells by vintage expressed by 12 first months totals for Middle Bakken/Three Forks/Sanish.
How to read the chart: The lines show the normal distribution for all studied wells started in 2008 – 2014, ref also the table in the upper left of the chart. 50 % of the 2014 wells have a total first 12 months flow flow of more than 86 kb while 43% were above the average of 92 kb. About 20% of the 2014 wells have a total first 12 months flow of 125 kb or more.
kb, kilo barrels = 1,000 barrels

Figure 06: The above chart shows developments in average well first year LTO totals (productivity) by vintage for some companies. The colored columns (at the 2013 and 2015 marks) show projected financial performance based on the average LTO well first year totals. For 2013, the chart is based on: WTI at $100/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 $50/b and a type well at $8M was found to have a 0% return with a total first year LTO flow at about 125 kb. The chart show 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 others upwards (moves the profitability bands upwards) and vice versa. Wells of the 2015 vintage (per September) are on a trajectory close to those of the 2014 vintage. kb, kilo barrels = 1,000 barrels

Figure 06: The above chart shows developments in average well first year LTO totals (productivity) by vintage for some companies. The colored columns (at the 2013 and 2015 marks) show projected financial performance based on the average LTO well first year totals.
For 2013, the chart is based on: WTI at $100/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 $50/b and a type well at $8M was found to have a 0% return with a total first year LTO flow at about 125 kb.
The chart show 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 others upwards (moves the profitability bands upwards) and vice versa.
Wells of the 2015 vintage (per September) are on a trajectory close to those of the 2014 vintage.
kb, kilo barrels = 1,000 barrels

For the 2008 vintage around 7% of the wells had a first year flow above 200 kb and for the 2014 vintage less than 3% (ref also figure 05).

The consequences of the collapse of the oil price are that the portion of the wells that are on profitable trajectories decreases.

Using the companies’ average well as a proxy, it becomes possible to identify what companies that have quality acreage that hold out expectations for profitability if present oil prices persists.

Digging deeper into the companies SEC 10-Q/K filings and holding this up with the quality of their acreage [wells] and how the companies responded to the collapse in the oil price, it is possible to identify those companies who are in it to turn a profit and what companies are caught on the treadmill to keep adding [unprofitable] wells in a bid to slow the decline in operating cash flow.

As extraction falls (as it will as the companies access to external funding dries up) this sets up a vicious dynamics as declining funding from declining cash flow results in lowered well additions, making it hard to offset the decline from the growing number of legacy wells.

So what about Restimulation (Refracking)?

Figure 07: The above chart shows developments by vintage in LTO extraction from the Middle Bakken/ Three Forks formations in Bakken (ND) as of January 2008 and of October 2014 for the Parshall pool/field.

Figure 07: The above chart shows developments by vintage in LTO extraction from the Middle Bakken/ Three Forks formations in Bakken (ND) as of January 2008 and of October 2014 for the Parshall pool/field.

Figure 08: The chart above shows developments in LTO extraction for the 2008 vintage from the Middle Bakken/ Three Forks formations in the Bakken(ND) for Mountrail as of January 2008 and of September 2015 split on Parshall and other Mountrail.

Figure 08: The chart above shows developments in LTO extraction for the 2008 vintage from the Middle Bakken/ Three Forks formations in the Bakken(ND) for Mountrail as of January 2008 and of September 2015 split on Parshall and other Mountrail.

EOG (Mountrail) and Marathon (Dunn and Mountrail) have apparently  restimulated (refracked) some of their 2008 vintage wells.

Figure 09: The chart above shows developments in LTO extraction for the 2008 vintage from the Middle Bakken/ Three Forks formations in the Bakken (ND) as of January 2008 and of September 2015 for EOG and Marathon.

Figure 09: The chart above shows developments in LTO extraction for the 2008 vintage from the Middle Bakken/ Three Forks formations in the Bakken (ND) as of January 2008 and of September 2015 for EOG and Marathon.

Figure 10: The chart shows the time series of some selected wells of 2008 vintage that apparently has been restimulated (refracked) during 2013 and 2014.

Figure 10: The chart shows the time series of some selected wells of 2008 vintage that apparently has been restimulated (refracked) during 2013 and 2014.

As far as actual data from restimulated wells provide any guidance for the economics thereof, it is that it requires a very high oil price to become profitable.

Restimulation have limited durability as the wells fall back to trend after 1 to 2 years.

Summary

The next 8 – 10 months LTO extraction from the Bakken will be in a steep decline, even if oil prices significantly rebounds. The future trajectory for LTO extraction from the Bakken is now driven by financial dynamics which has to run its course and a lasting, low oil price will cause serious financial stresses on most of the LTO companies in the Bakken.

 —

 We apply fight-or-flight reflexes not only to predators, but to data itself.

–Chris Mooney

Written by Rune Likvern

Monday, 30 November, 2015 at 21:49

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