FRACTIONAL FLOW

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

Extraction developments of LTO from Bakken may be followed by county, formation, vintage of wells, and one important source to understand the developments are coming from studying the developments by companies. Holding this up with companies’ financial statements (10-K and 10-Q) is an invaluable source about the companies, their financial capabilities and their strategies. This information is paramount to understand the developments in LTO extraction from Bakken and provides valuable insights into what to expect of future developments.

To get some understanding of what will drive future developments, it is helpful to look at individual companies.

Amongst all the companies operating in Bakken I selected for this post to present a closer look at 3 of the biggest companies in Bakken; Continental Resources, EOG Resources and Whiting Petroleum.

These 3 companies were found to be representative for several of the companies with regard to a range of variation in quality of wells, development strategies, use of debt, asset sales and not least what their responses to oil price changes may reveal.

  1. For Q1 – 15 the companies involved in LTO extraction in Bakken used an estimated $4 Billion (CAPEX) for well manufacturing and an estimated $2.3 Billion was from external sources, primarily from equity and asset sales and assuming more debt.
    The “average” well with around 90 kb [90,000 barrels] 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 $60/Bbl (WTI).
  2. The break even price increases with increases in the return requirement.
  3. This analysis shows that the companies have deployed different strategies as responses to the decline in the oil price, which will affect future developments in LTO extraction.

Figure 1: The chart above shows development in Light Tight Oil (LTO) extraction from January 2009 and as of March 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. Note that the spread between WTI and Bakken LTO wellhead has remained relatively high and fairly stable during the recent year.

Figure 1: The chart above shows development in Light Tight Oil (LTO) extraction from January 2009 and as of March 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. Note that the spread between WTI and Bakken LTO wellhead has remained relatively high and fairly stable during the recent year.

Since September 2014 and as of March 2015 LTO extraction from Bakken(ND) has flatlined at  1.12 – 1.16 Mb/d.

With an oil price below $50/Bbl (WTI) the companies involved in extraction of LTO in Bakken will face several financial challenges.

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

Production data for Bakken, North Dakota: Monthly Production Report Index

Formation data from: Bakken Horizontal Wells By Producing Zone

Data on wells kindly made available by Enno Peters’ excellent and tireless work.

Figure 2: The chart above shows an estimate in development of cumulative net cash flows post CAPEX for manufacturing LTO wells in Bakken (ND) as of January 2009 and as of March 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 from 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, dividend payouts and retained earnings. 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 2: The chart above shows an estimate in development of cumulative net cash flows post CAPEX for manufacturing LTO wells in Bakken (ND) as of January 2009 and as of March 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 from 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, dividend payouts and retained earnings.
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).

With the decline in the oil price some of the Bakken LTO producers went counter cyclical and took on more debt and sold equity and assets in a bid to sustain/grow oil production. The logic at work here is that any decline in prices should be made up by volume, thus profitability considerations were sidelined.

The decline in the oil price and the aggregate increase in the use of debt made the leverage in March -15 reach new highs.

The LTO Break Even Flow

At $60/Bbl (WTI) it is estimated that wells with a total 1st year extraction of 90 kb is likely to make a profit and returns improves with increased flow.

At $100/Bbl (WTI) it is estimated that wells with a total 1st year extraction of 55 kb is likely to make a profit and returns improves with increased flow.

Table 1: The table lists some key metrics for the companies studied.

Table 1: The table lists some key metrics for the companies studied.

Table 1 illustrates how the companies responded to the decline in the oil price and it shows the mismatch between total number of wells, wells added during Q1 – 2015 and portion of total extraction. Whatever metric for efficiency is applied, EOG comes out on top.

Figure 3: The chart above (stacked areas) shows developments in LTO extraction by the 3 presented companies and total. NOTE: The chart does not include contributions from wells starting to flow prior to 2008 for the presented companies and the contributions from these wells normally diminishes as the wells ages.

Figure 3: The chart above (stacked areas) shows developments in LTO extraction by the 3 presented companies and total.
NOTE: The chart does not include contributions from wells starting to flow prior to 2008 for the presented companies and the contributions from these wells normally diminishes as the wells ages.

EOG came in early and they also have, by a wide margin, the best of the wells of the companies presented, refer also figure 7.

There is something about watching those who moves in and out early. EOG may be one to watch.

Continental Resources

Figure 4: The chart above shows developments by vintage in LTO extraction for Continental Resources in Bakken (ND) as of January 2008 and of March 2015 [right hand scale]. Development in the oil price (WTI) black line is shown versus the left hand scale. NOTES: The chart shows developments in total LTO extraction from wells which Continental Resources were listed as the business owner per March 2015. Continental’s entitlement volumes  needs to be adjusted according to their Working Interest (WI) in each well. The chart does not include contributions from wells starting to flow prior to 2008 and the contributions from these wells normally diminishes as the wells ages.

Figure 4: The chart above shows developments by vintage in LTO extraction for Continental Resources in Bakken (ND) as of January 2008 and of March 2015 [right hand scale]. Development in the oil price (WTI) black line is shown versus the left hand scale.
NOTES: The chart shows developments in total LTO extraction from wells which Continental Resources were listed as the business owner per March 2015. Continental’s entitlement volumes needs to be adjusted according to their Working Interest (WI) in each well.
The chart does not include contributions from wells starting to flow prior to 2008 and the contributions from these wells normally diminishes as the wells ages.

Figure 5: The chart shows the development in average total LTO extraction by vintage for LTO wells were Continental Resources was listed as the business owner per March 2015. NOTE: Data for 2014 are not complete with first year totals for all wells.

Figure 5: The chart shows the development in average total LTO extraction by vintage for LTO wells were Continental Resources was listed as the business owner per March 2015.
NOTE: Data for 2014 are not complete with first year totals for all wells.

Continental went counter cyclical with the decline in the oil price and continued to grow LTO extraction.

The average well for Continental does not make commercial sense at present oil prices, which means only a few wells have the prospect of becoming profitable.

EOG Resources

Figure 6: The chart above shows developments by vintage in LTO extraction for EOG Resources in Bakken (ND) as of January 2008 and of March 2015 [right hand scale]. Development in the oil price (WTI) black line is shown versus the left hand scale. NOTES: The chart shows developments in total LTO extraction from wells which EOG Resources were listed as the business owner per March 2015. EOG’s entitlement volumes  needs to be adjusted according to their Working Interest (WI) in each well. The chart does not include contributions from wells starting to flow prior to 2008 and the contributions from these wells normally diminishes as the wells ages.

Figure 6: The chart above shows developments by vintage in LTO extraction for EOG Resources in Bakken (ND) as of January 2008 and of March 2015 [right hand scale]. Development in the oil price (WTI) black line is shown versus the left hand scale.
NOTES: The chart shows developments in total LTO extraction from wells which EOG Resources were listed as the business owner per March 2015. EOG’s entitlement volumes needs to be adjusted according to their Working Interest (WI) in each well.
The chart does not include contributions from wells starting to flow prior to 2008 and the contributions from these wells normally diminishes as the wells ages.

Figure 7: The chart shows the development in average total LTO extraction by vintage for LTO wells were EOG Resources was listed as the business owner per March 2015. NOTE: Data for 2014 are not complete with first year totals for all wells.

Figure 7: The chart shows the development in average total LTO extraction by vintage for LTO wells were EOG Resources was listed as the business owner per March 2015.
NOTE: Data for 2014 are not complete with first year totals for all wells.

Of the companies presented EOG has by a wide margin the most productive wells and so far their wells will be profitable at present price levels if the productivity trends from 2014 are continued.

It is worth noting that EOG adjusts their well manufacturing with movements in the oil price. This strongly suggests that EOG is in the LTO business for successful value capture (profitability).

Whiting Petroleum

Figure 8: The chart above shows developments by vintage in LTO extraction for Whiting Petroleum in Bakken (ND) as of January 2008 and of March 2015 [right hand scale]. Development in the oil price (WTI) black line is shown versus the left hand scale. NOTES: The chart shows developments in total LTO extraction from wells which Whiting Petroleum was listed as the business owner per March 2015. Whiting’s entitlement volumes  needs to be adjusted according to their Working Interest (WI) in each well. The chart does not include contributions from wells starting to flow prior to 2008 and the contributions from these wells normally diminishes as the wells ages.

Figure 8: The chart above shows developments by vintage in LTO extraction for Whiting Petroleum in Bakken (ND) as of January 2008 and of March 2015 [right hand scale]. Development in the oil price (WTI) black line is shown versus the left hand scale.
NOTES: The chart shows developments in total LTO extraction from wells which Whiting Petroleum was listed as the business owner per March 2015. Whiting’s entitlement volumes needs to be adjusted according to their Working Interest (WI) in each well.
The chart does not include contributions from wells starting to flow prior to 2008 and the contributions from these wells normally diminishes as the wells ages.

Figure 9: The chart shows the development in average total LTO extraction by vintage for LTO wells were Whiting Petroleum was listed as the business owner per March 2015. NOTE: Data for 2014 are not complete with first year totals for all wells.

Figure 9: The chart shows the development in average total LTO extraction by vintage for LTO wells were Whiting Petroleum was listed as the business owner per March 2015.
NOTE: Data for 2014 are not complete with first year totals for all wells.

The earliest of Whiting’s wells was more productive than the average, while wells for 2011, 2012 and 2013 were poorer and so far the total for wells of 2014 vintage has performed close to the average. At $60/Bbl (WTI) these wells should make some profit.

Summary

This study shows that the companies involved in LTO extraction in Bakken respond differently to movements in the oil price.

As LTO extraction is heavily front end loaded, with most of its extraction early, a sensible strategy would be to adjust the scope of well manufacturing with price movements.

Some companies are clearly value captures that besides having some of the most productive wells also adjust their well manufacturing with movements in the oil price.

It appears strange that of the presented companies the one with the poorest wells, which likely are unprofitable at $60/Bbl [WTI], responded to the recent price decline by growing its total extraction. This may reflect a bet that the oil price soon will make a strong rebound.

Any forecasts for future developments in LTO extraction from Bakken should consider the different strategies amongst the involved companies, their attitude for value capture and their future access to capital, being the combinations from cash flow from operations, equity and assets sales and their capacities for assuming more debt.

When it comes to how well productivity develops, we just have to await actual data for LTO extraction and keep a watchful eye on the developments in water cut and Gas Oil Ratio (GOR).

Written by Rune Likvern

Sunday, 7 June, 2015 at 20:33

3 Responses

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  1. Thanks for another detailed high quality post Rune. It is a worrying sign that even while so far production in the Bakken peaked in Dec 2014, free cash flows have hit the deepest negative territory in 2015.

    Enno

    Sunday, 7 June, 2015 at 21:43

  2. Thanks a lot for these reports, quite “funny” that while Bakken seems to have peaked in Dec 2014 (do you also follow eagle ford ?), the “shale oil revolution” and associated “major shift” was the key message of last BP report and speech by chief economist …

    yt75

    Monday, 15 June, 2015 at 08:40

    • This “major shift” may soon prove to be much different than most envision.
      “And no on saw it coming.”

      Shale oil (LTO) appears to be very much driven by a high oil price and financials (primarily debt).
      I do not follow Eagle Ford very closely, but monitors developments in Marcellus (shale gas).

      Rune Likvern

      Monday, 15 June, 2015 at 17:21


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