FRACTIONAL FLOW

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More on LTO Economics in the Bakken

The goal for any commercial company is to make as high as possible profit and returns on invested (employed) capital, primarily the owners’ capital, equity.

Light Tight Oil (LTO) extraction from the Bakken and Three Forks formations in North Dakota had a new high of 1,17 Mbo/d in Apr-18 according to data published in Jun-18 by the North Dakota Industrial Commission (NDIC).

This article is an update of this (which has more details on specific costs to which there are small changes) and is a small expansion focused on profitability/financial metrics.

  • Scenarios were run there no wells were added as of Jan-19 (in the Bakken, Three Forks formations) with an initial flow above 1,2 Mbo/d to get estimates on NPV (DCF) and returns for the project and on equity (owners’ capital), ROE and ROI with a sustained oil price of $60/bo and what oil price would provide the project with a 7% return (ref table 1).
    All at the wellhead (WH).
    These runs had cut off end 2040.
    The objectives with such scenario analysis is to establish baselines from which it becomes possible to follow developments in several financial metrics, also adjusted for oil price movements.
    Applied to companies, it provides for benchmarking of companies’ management performances.
  • At $60/bo (and $2,50/Mcf for natural gas) the Bakken project would return about 4%.
  • A 7% return was obtained with a sustained oil price of $73/bo (and $3,00/Mcf).
    • The above estimates do not include costs for acreage, 800 Drilled UnCompleted (DUC) wells with an estimated total cost (employed capital) of $2,0B – $2,4B, any refracking (ref Marathon), flared gas and future costs for Plugging & Abandonment (P&A) for about 12 000 wells started as of Jan-09 to end 2018, estimated at a total cost of $1,8B – $2,4B and recognized write downs.
  • Including the items described above, the estimates show a full cycle return of 7% for the Bakken as one big LTO project would be achieved at a sustained future oil price at about $80/bo [$90/bo WTI].
  • One of the best and most reliable metrics for investors are NPV projections for Equity (Owners’ Capital).
    A NPV projection for equity that comes in at about 0 with a discount rate of 10% (the higher the better) is considered acceptable (reference also tables 1-5).
    This metric allows comparisions across sectors.
  • A run was done to estimate the effects from pushing back the time from where no wells were added with 5 years (from 2019 to 2024) while remaining close to cash flow neutral (all other things kept equal). This reduces the return for both the project and equity (owners’ capital).
    The discounted return on equity (owners’ capital) was lowered from 14% to 10% with $73/bo at WH.
    Alternatively a higher oil price is required to achieve some targeted return.
  • By applying financial leverage in the extractive industries, like oil extraction, it allows to extract the reserves faster (accelerate the depletion). In the Bakken the use of high financial leverage explains the rapid buildup in extraction levels.
    In this article financial leverage expresses the ratio of debt [inorganic funding] to equity [owners’ capital] used in a company’s investment.
    When financial leverage works, it boosts return (acts as a multiplier) on owners’ capital.
    If it does not work (what many companies painfully discovered after the oil price collapsed in 2014), leverage works fast in the opposite direction and destroys owners’ capital.

    • From companies’ SEC reports it was found that there is a huge span in their financial performances in the Bakken, one major big oil company has lost all their equity of $4+Billion [in the Bakken], one was found to have big negative retained earnings (accumulated deficit) of $2+Billion and then there are several companies on trajectories towards varying degrees of profitability.
  • The 3 years, 2015-2017 with the oil price under $50/bo left primarily the wells of the 2014 – 2016 vintages (ref also figure 2), suffering from the low oil price, and it is now projected these vintages could incur total losses (write downs) of $6B – $8B with a sustained oil price of $60/bo.
    These losses are and/or will be recognized on the companies balance sheets (equity, reduced owners’ capital) as the wells end their economic life and are Plugged & Abandoned (P&A).

    • Older vintages and future wells could fully or partially make up (cover) for these losses from their profits at a sustained oil price of $60/bo. A lasting oil price above $60/bo speeds the healing.
      Irrespective of a future higher oil price and how this probable loss is handled by the oil companies, the 2014 – 2016 vintages will for many years provide strong headwinds to the profitability for many companies in the Bakken.
      This is one of the many things that is hard (close to impossible) to identify from the companies’ SEC filings.

This post includes some estimates with some profitability metrics for the average 2017 vintage well for 2 price scenarios and how a company with solid finances and strong discipline can boost discounted return on equity.
This also illustrates why project NPVs, undiscounted cash flows, time to pay outs, ROE and ROI may be poor metrics when analyzing and ranking several projects and/or companies.
Short story, several metrics should be estimated and compared to get the best possible information about the prospects for financial profitability for any project/company.

Figure 1 Bakken annual NCF and Cumulative 2009 to Apr 2018

Figure 1: The chart above shows the estimated net cash flows by year [black columns]. The red area shows the estimated cumulative net cash flow since Jan-09 and per Apr-18. 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 was in force. Price of oil, monthly North Dakota Sweet (NDS) and realized gas price; the average from several companies’ quarterly reports.

NOTE; the chart in figure 1 shows an estimate (red area) on the development of total capital employed (equity and borrowed) (as from Jan-09 to Apr-18) that first needs to be recovered before profits can be made.

The payouts were reached late 2022 at $60/bo and late 2021 at $73/bo.

The chart does not give any indication about future profits or losses.

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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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Will the Bakken Red Queen Outrun Growth in Water Cut?

This post presents a closer examination of actual data on Light Tight Oil (LTO) extraction, developments in water cut and Gas Oil Ratio (GOR) for some pools and individual wells in the Middle Bakken and Three Forks formations in North Dakota.

LTO extraction’s primary drive mechanism is (differential) pressure and there are some noticeable trends for LTO extraction from Bakken:

  • LTO productivity (measured as average totals by vintage) in 2014 have increased, most notably from the Middle Bakken formation which has better well productivity than Three Forks.
    There are differences to LTO productivity developments amongst the pools.
  • Water cut; generally increases as the wells ages.
    An indicator for depletion.
  • Water cut; generally increases for newer wells.
    This suggests that the areas with the highest oil saturation has been developed.
  • Gas Oil Ratio (GOR, produced and expressed as Mcf/Bbl); generally increases as the well ages. 
  • What appears to characterize a Bakken sweet spot is the presence of natural fractures (favorable geology), high oil saturation and a pressure above hydrostatic pressure.

Further, this post also has a brief look into well economics and describes how well manufacturing is likely to be affected by the decline in the oil price and what this may entail if a lower oil price ($70/Bbl, WTI) is sustained.

Figure 01: The chart above shows development in the water cut [water cut = [water/(water + LTO)] for the “average” wells by vintage in North  Dakota. Produced water (brine) is transported to dedicated disposal sites. Chart by Enno Peters.

Figure 01: The chart above shows development in the water cut [water cut = [water/(water + LTO)] for the “average” wells by vintage in North Dakota. Produced water (brine) is transported to dedicated disposal sites.
Chart by Enno Peters.

What is fascinating about LTO wells in Bakken is that the individual wells appear to have their own “personality” when it comes to productivity, surrounding rock properties, water/oil saturation and GOR which makes well management (of close to 9,000 “personalities”) a paramount task.

This post contains in total 30 charts that hopefully are self explanatory.

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Growth in Global Total Debt sustained a High Oil Price and delayed the Bakken “Red Queen”

The saying is that hindsight (always) provides 20/20 vision.

In this post I present a retrospective look at my prediction from 2012 published on The Oil Drum (The “Red Queen” series) where I predicted that Light Tight Oil (LTO) extraction from Bakken in North Dakota would not move much above 0.7 Mb/d.

  • Profitable drilling in Bakken for LTO extraction has been, is and will continue to be dependent on an oil price above a certain threshold, now about $68/Bbl at the wellhead (or around $80/Bbl [WTI]) on a point forward basis.
    (The profitability threshold depends on the individual well’s productivity and companies’ return requirements.)
  • Complete analysis of developments to LTO extraction should encompass the resilience of the oil companies’ balance sheets and their return requirements.

Figure 01: The chart above shows development in Light Tight Oil (LTO) extraction from January 2009 and as of August 2014 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. The spread between WTI and Bakken wellhead has widened in the recent months.

Figure 01: The chart above shows development in Light Tight Oil (LTO) extraction from January 2009 and as of August 2014 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. The spread between WTI and Bakken wellhead has widened in the recent months.

What makes extraction from source rock in Bakken attractive (as in profitable) is/was the high oil price and cheap debt (low interest rates). The Bakken formation has been known for decades and fracking is not a new technology, though it has seen and is likely to see lots of improvements.

LTO extraction in Bakken (and in other plays like Eagle Ford) happened due to a higher oil price as it involves the deployment of expensive technologies which again is at the mercy of:

  • Consumers affordability, that is their ability to continue to pay for more expensive oil
  • Changes in global total debt levels (credit expansion), like the recent years rapid credit expansion in emerging economies, primarily China.
  • Central banks’ policies, like the recent years’ expansions of their balance sheets and low interest rate policies
    • Credit/debt is a vehicle for consumers to pay (create demand) for a product/service
    • Credit/debt is also used by companies to generate supplies to meet changes to demand
    • What companies in reality do is to use expectations of future cash flows (from consumers’ abilities to take on more debt) as collateral to themselves go deeper into debt.
    • Credit/debt, thus works both sides of the supply/demand equation
  • How OPEC shapes their policies as responses to declines in the oil price
    Will OPEC establish and defend a price floor for the oil price?

I have recently and repeatedly pointed out;

  • 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.

Oil is a global commodity which price is determined in the global marketplace.

Added liquidity and low interest rates provided by the world’s dominant central bank, the Fed, has also played some role in the developments in LTO extraction from the Bakken formation in North America.

As numerous people repeatedly have said; “Never bet against the Fed!” to which I will add “…and China’s determination to expand credit”.

Let me be clear, I do not believe that the Fed’s policies have been aimed at supporting developments in Bakken (or other petroleum developments) this is in my opinion unintended consequences.

In Bakken two factors helped grow and sustain a high number of well additions (well manufacturing);

  • A high(er) oil price
  • Growing use of cheap external funding (primarily debt)

In the summer of 2012 I found it hard to comprehend what would sustain the oil price above $80/Bbl (WTI).

The mechanisms that supported the high oil price was well understood, what lacked was documentation from authoritative sources about the scale of the continued accommodative policies from major central banks’ (balance sheet expansions [QE] and low interest rate policies) and as important; global total credit expansion, which in recent years was driven by China and other emerging economies.

I have described more about this in my post World Crude Oil Production and the Oil Price.

 

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World Crude Oil Production and the Oil Price

In April 2012 I published this post about World Crude Oil Production and the Oil Price (in Norwegian) which was an attempt to describe the developments in the sources of crude oils (including condensates), tranches of total life cycle costs (that is [CAPEX {inclusive returns} + OPEX] per barrel  of oil) and something about the drivers for the formation of the oil price.

Rereading the post and as time passed, I learnt more and therefore thought it appropriate to revisit and update the post as it in my opinion contains some topics from what I have observed, learned and discussed that have been given poor attention and appears poorly understood.

I will continue to pound the message that oil prices are also subject to the reality of;

  • “Demand is what the consumers can pay for!”

Figure 1: The chart above shows the developments in the oil price [Brent spot] and the time of central banks’ announcements/deployments of available tools to support the global financial markets which the economy heavily relies upon. The financial system is virtual and thus highly responsive. The chart suggests causation between FED policies and movements to the oil price.

Figure 1: The chart above shows the developments in the oil price [Brent spot] and the time of central banks’ announcements/deployments of available tools to support the global financial markets which the economy heavily relies upon. The financial system is virtual and thus highly responsive.
The chart suggests causation between FED policies and movements to the oil price.

The four big central banks, BoE, BoJ, ECB and the Fed expanded their balance sheets with $6 – 7 Trillion following the Lehman collapse in the fall of 2008. These liquidity injections are about to end.

Since 2008 most of the advanced economies’ credit expansions originated from the central banks, the lenders of last resort. Central banks are collateral constrained.

The consensus about the oil price collapse during the recent weeks is attributed to waning global demand and growth in  supplies.

All eyes are now on OPEC.

  • 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.

For more than a decade, I have carefully studied the forecasts (and been involved in numerous fruitful [private] discussions) from authoritative sources like the Energy Information Administration (EIA) and the International Energy Agency (IEA) including the annual outlooks from several of the major oil companies and I did NOT find that any of these takes into consideration changes to global credit/debt [growth/deleveraging], levels of total global credit/debt and interest rates.

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