FRACTIONAL FLOW

Fractional flow, the flow that shapes our future.

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.

Acknowledgements

This post/analysis results from several months of work and discussions/communications with representatives of US oil companies. Some are also invested in LTO extraction.

To understand the rapid growth in LTO extraction the total use of external funding from primarily debt and assets/equities sales was estimated. The estimates reflect declines in well costs and operating costs from efficiency improvements. Costs are weighted averages of several companies.

Figure 2: 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 January 2016 (red area and rh scale) and estimated monthly net cash flows post CAPEX (black columns and lh scale). 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 18%, production tax of 5%, an extraction tax of 5.5%, LOE at $9/Bo, and a weighted interest of 6% on debt (before any corporate tax effects, which now adds around $5/Bo in financial costs) and income from natural gas/NGPL sales (which now and on average grosses around 1.3 Mcf/Bo). 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). Estimates do not include costs of DUCs. On average, one DUC comes with a cost of about $3 - $3.5M. NOTE: A negative cash flow does not automatically translate into an uneconomic/unprofitable project/venture. And vice versa.

Figure 2: 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 January 2016 (red area and rh scale) and estimated monthly net cash flows post CAPEX (black columns and lh scale).
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 18%, production tax of 5%, an extraction tax of 5.5%, LOE at $9/Bo, and a weighted interest of 6% on debt (before any corporate tax effects, which now adds around $5/Bo in financial costs) and income from natural gas/NGPL sales (which now and on average grosses around 1.3 Mcf/Bo).
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).
Estimates do not include costs of DUCs. On average, one DUC comes with a cost of about $3 – $3.5M.
NOTE: A negative cash flow does not automatically translate into an uneconomic/unprofitable project/venture. And vice versa.

The chart illustrates that as the oil price started to decline in the summer of 2014, the LTO companies went counter cyclical and increased their spending. They likely entered into a bet that the oil price would soon recover to former profitable levels of $100/bo [WTI]. It appears as the companies loaded up on liquidity following the oil price first leg down to ensure they could sustain momentum through what was expected to be a brief downturn in the oil price.

In the Bakken for 2015 it is estimated that about $6 Billion of external funding was used in addition to net cash flow from operations.

As the oil price entered its second leg down in the summer of 2015, the LTO companies drastically cut back on their spending and started winding down their activities.

Well economics

Figure 3: The chart above shows development of some Return On Investment (ROI) versus the wellhead oil price and EUR. Included is a table that shows how this translates into Net Present Values (NPV) discount rates. Royalty is the total of ordinary royalties and Over Riding Royalty Interest (ORRI). Return On Investment (ROI), ROI = (Gain from Investment - Cost of Investment) / Cost of Investment

Figure 3: The chart above shows development of some Return On Investment (ROI) versus the wellhead oil price and EUR. Included is a table that shows how this translates into Net Present Values (NPV) discount rates.
Royalty is the total of ordinary royalties and Over Riding Royalty Interest (ORRI).
Return On Investment (ROI), ROI = (Gain from Investment – Cost of Investment) / Cost of Investment

Until the debt is reduced [principal paid down], total interest costs and G&A are highly inelastic, meaning that declines to total production volumes will require a higher oil price to make investments in further well manufacturing [drilling and/or completion of additional wells {DUCs}] profitable.

This is the effects of the Financial Red Queen. A sustained low oil price makes fewer LTO wells profitable and results in a decline of well additions that falls below what is needed to sustain production, leading to lower production [flow] and increases in some of the specific costs [like G&A and interest costs].

Due to the wells’ steep declines and if wells added falls below some threshold, companies risk to see their RRR fall below 100% and thus a reduction in their collateral.

For all producing wells less than 1% in Middle Bakken/Three Forks (out of a total of about 10,500) are on a trajectory to recover more than 1 Million barrels [Mb] LTO.

Some key data and metrics used for the study

Total finance costs (interest payments) and General & Administrative (G&A) are relatively inelastic to extraction levels.

Table 1: The table shows some key financial data and metrics for Whiting that was one of the companies studied and that formed the basis for the generic company.

Table 1: The table shows some key financial data and metrics for Whiting that was one of the companies studied and that formed the basis for the generic company.

North Dakota Sweet was for Feb-16 $18.07/bo and Mar-16 $26.62/bo [Source: Flint Hills].

For 2015, ref table 1, Whiting’s total specific operating costs was about $21/boe. Each barrel of LTO comes with about 1.2 – 1.3 Mcf natural gas where, in 2015, there was a loss of $1,28/Mcf, resulting in specific operating costs (losses somehow have to be covered) at $22 – $23/bo.

For Feb-16, Whiting likely had operating losses of $4 – $5/bo. Losses from operations were also identified in other LTO companies.

The Generic LTO Company

For the study a generic company was derived from data from actual companies. What follows is a forecast LTO extraction profile, assuming no well additions post Jan-16 for this generic company. This profile was used for several oil price scenarios (2 scenarios presented here). The objective was to see how the cumulative net cash flow from operations measured against the debt redemption profile (bond hurdles), alternatively get a first estimate on how much funding there would be available for well manufacturing as the bond hurdles were approached.

Figure 4: The chart shows actual total LTO extracted by the generic company acting as an operator and how the volumes are split between royalties, other partners with Working Interests (WI) and the company’s Net Revenue Interests (NRI or entitlement volumes). The dotted line shows a forecast of the company’s NRI (entitlement volumes) as from Feb-16 towards end 2019 with no wells added post Jan-16. Working Interest (WI) is the financial obligations of the company in one or several joint ventures (JV).

Figure 4: The chart shows actual total LTO extracted by the generic company acting as an operator and how the volumes are split between royalties, other partners with Working Interests (WI) and the company’s Net Revenue Interests (NRI or entitlement volumes).
The dotted line shows a forecast of the company’s NRI (entitlement volumes) as from Feb-16 towards end 2019 with no wells added post Jan-16.
Working Interest (WI) is the financial obligations of the company in one or several joint ventures (JV).

The NRI [entitlement] volumes were used to estimate monthly net cash flows from operations [ex hedges, natural gas and NGLs]. Several companies disclosed in their SEC 10-K filings in 2015 that they had losses on natural gas sales ranging $1 – $2/Mcf. On average, one barrel of LTO comes with 1.2 – 1.3 Mcf natural gas.

Figure 5: The chart shows the monthly net cash flow from operations [columns and left hand scale] and the cumulative net cash flow from operations [lines and right hand scale] versus time. {Red columns/line with wellhead price at $40/bo. Blue columns/line with wellhead price at $60/bo} NOTE: Scaling of left hand vertical axis.

Figure 5: The chart shows the monthly net cash flow from operations [columns and left hand scale] and the cumulative net cash flow from operations [lines and right hand scale] versus time.
{Red columns/line with wellhead price at $40/bo. Blue columns/line with wellhead price at $60/bo}
NOTE: Scaling of left hand vertical axis.

The reason why net cash flows from operations for the price scenario with $40/bo at WH becomes negative [in early 2018] is the combined effects of declining extraction and (primarily) the interest costs from the total debt overhang.

  • Normally oil/natural gas transportation contracts are “ship or pay”.
    As LTO extraction declines, a declining volume has to cover total transport costs, thus specific transport costs [$/Bo or Mcf] goes up. The effect of this has not been included in what is presented.
    There has been reports about companies in bankruptcy that had rulings to have their transport contracts declared void based on that a bankruptcy constitute a force majeure. If such rulings prevail, it will make it hard on transport companies that operate on small profit margins.
  • Estimates do not include costs for any outstanding credit on credit facilities.

Next step shows the estimated cumulative net cash flows from operations from the 2 price scenarios together with the debt retirement profiles (shown as stacked hurdles).

Figure 6: The chart shows how the net cumulative cash flow from operations for the 2 price scenarios [ref figure 5] as they encounter the bond hurdles which are shown stacked along the time axis.

Figure 6: The chart shows how the net cumulative cash flow from operations for the 2 price scenarios [ref figure 5] as they encounter the bond hurdles which are shown stacked along the time axis.

The results from the simulations show that the generic company will face challenges with clearing the first bond hurdle and future ones at the presented price scenarios and that a much higher oil price is required to clear all the bond hurdles.

This analysis looked at several companies heavily invested in the Bakken and some performs somewhat better and others somewhat poorer than what is shown in figure 6.

Keep in mind there is still some time before the first hurdle is reached. Oil price will remain the most important factor and management may succeed in restructuring debt [and (re)negotiate lower interest rates] and cut costs. It is expected that the management will operate prudently to demonstrate their company’s intentions of clearing the bond hurdles.

The rationale to continue to invest in new wells [drilling and/or completion {DUCs}] is there, if the investment and more are recovered before the debt hurdles are reached.

The sweet spots

Figure 7: The Parshall pool/field in Mountrail county is where the Bakken LTO took of from and Parshall has favorable geological properties that made it a sweet spot.

Figure 7: The Parshall pool/field in Mountrail county is where the Bakken LTO took of from and Parshall has favorable geological properties that made it a sweet spot.

The sweet spots, like Grail [McKenzie] and Parshall are about to become saturated with wells and what remains are acreage with generally poorer geological properties which requires higher prices to become profitable. If and/or when well manufacturing picks up again it should also be expected that service companies’ pricing will reflect their needs to earn a decent profit.

Visualizing US shale oil production

Enno Peters’ excellent site Visualizing US shale oil production (under construction) is highly recommended for those who want to explore detailed information about developments for several US shale oil plays (Bakken, Eagle Ford, Niobrara, Permian) and allows to view developments by companies, pools, formations and much more.

The site allows viewing developments in well productivities by vintage and company. For Bakken it shows some improvements in recent years in total extracted oil.

“If you look for truth, you may find comfort in the end; if you look for comfort you will not get either comfort or truth, only . . . wishful thinking to begin, and in the end, despair.”

C.S. Lewis

Written by Rune Likvern

Wednesday, 6 April, 2016 at 21:51

4 Responses

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  1. Nice presentation, very thorough and well presented. One clarification – you state $60 WH as a threshold for well development to pick up, but all the accompanying detail would indicate it needs to be higher (e.g. WTI to ND sweet discount, transport costs, exhaustion of sweet spots, negative cash flow at $100+ WTI prices, state of the local service industry, lack of funding, and I’d add maybe a loss of appetite for risk in the E&P companies). Please clarify.

    AJY

    Thursday, 7 April, 2016 at 08:27

    • Hello AJY and thanks.

      In short, I do not expect activity levels to pick up to past levels and I expect the peak in Bakken to be history.

      At $60/bo (WH) a well with an expected EUR of about 450 kbo will be on a profitable trajectory. More than 10% have historically been at this level. Companies may have been better at high grading acreage.

      Further I suspect that such a price [$60/b] will entice some to complete their inventory of DUC’s (may incur a loss/write down), but on a point forward basis it looks all right [only costs for the completion] and gives much needed cash flow.

      Negative cash flow does not automatically translate into unprofitable investment. One needs to look at full life cycle economics.

      Looking a little further ahead I suspect that the full cycle price needed for profitability will move higher, poorer acreage, higher costs.
      Presently and for the average well the profitability threshold is about $90/bo WTI.

      I also believe there will be a loss of risk appetite for E&P companies and this affects funding, like sale of debt, restructuring of existing debt.
      For many creditors it will now be about Return of Capital.
      There is also psychology/sentiment in play here, during the boom everyone wants in, during the bust no one can get out fast enough.

      Rune Likvern

      Thursday, 7 April, 2016 at 16:19

  2. Rune. Excellent, in depth analysis. It needs to be read closely to get all the detail, I just hope enough people do. Very few are capable of in depth analysis these days.

    The effect of debt cannot be overstated with regard to LTO, without massive borrowing, the “shale revolution” as dubbed by the media, never occurs.

    LTO has greatly damaged almost all world oil producer’s balance sheets, due to it’s oversupply, which was met by further oversupply by KSA, Russia and Iraq. None took too kindly to the “Saudi America” comments.

    Almost none of the LTO companies have PDP PV10 greater than long term debt, even at 2015 SEC prices, which are almost $15 higher than present for WTI. At $35 WTI, future cash flows are minimal, as you state, not anywhere nearly enough to pay interest and retire debt, even if CAPEX is almost eliminated. Yet, they continue to be darlings of Wall Street, violating every long held E & P valuation metric.

    You have been criticized by some for expecting a Bakken peak at a lower level than what occurred. I think the only thing you underestimated was just how totally irresponsible the Bakken companies would be with debt. The two largest, CLR and WLL, apparently have abandoned completions in the Bakken for the remainder of 2016. The DUC phenomenon really is a head scratcher, yes they both are still drilling in the Williston Basin. I cannot think of a historic industry corollary to the present of drilling wells with no intention of completing them for 1+ years. The mentioned companies have combined long term debt exceeding $12 billion. Will be interesting to see how it plays out for them and the others.

    I think 2016 will be extremely tough on almost all US producers. It is very difficult for us for sure. Thanksgiving, 2014 will live in infamy for the conventional producers in the US, most of whom were just trying to maintain production within cash flows. That has been impossible since 12/14.

    Due to the LTO boom and resulting oil bust, the US will now be very dependent on LTO and imports. GOM will soon peak. Conventional lower 48 and Alaska will likely never produce as much tomorrow as they did yesterday.

    Keep up the good work!

    shallow

    shallow sand

    Thursday, 7 April, 2016 at 19:43

    • shallow, thanks!

      I expect many will describe the article as “rich”.
      It is a challenge to describe such a complex business model and at the same time make it accessible to as many as possible. Finance is not what is on most people’s radars.
      The targeted audiences get the points.

      Back in 2012 I expected oil prices to come down a bit [not exactly when, and how low], but I never expected the collapse and the low levels we have seen in recent months.
      In 2012 the model was debt constrained (and looked at several oil prices), meaning it allowed total debt to grow to a certain level and then that level was sustained.
      The debt level should allow to ride out a lower oil price.

      In hindsight this should have been described, even though I in some follow-ups tried to focus on the amount of external funding [primarily debt] and profitability.
      Focus then was on volume and not profitability!

      Leverage with debt allows for increased returns on equity if deployed wisely and it works, if the bets turns sour it rapidly wipes out equity and more.

      Rune Likvern

      Thursday, 7 April, 2016 at 20:50


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