FRACTIONAL FLOW

Posts Tagged ‘LTO

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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A little on the Profitability of the Bakken(ND)

In the first part of this post I present an update on the profitability for Light Tight Oil (LTO) extraction in the Bakken (ND) as one big project.

This is followed with economic life cycle analysis for the average LTO well of the 2014, 2015 and 2016 vintages in the Bakken.

This analysis found that companies in aggregate continue to outspend net cash flows from operations and for 2017 this is now expected to total $2 – $3 Billion.

  • The strong growth and sustained high LTO extraction from the Bakken were facilitated by considerable amounts of debts. The growth in total debts outstanding (employed capital) continues to grow, albeit at a slower pace.
  • With oil prices sustained at present levels the total employed capital (primarily debt) constitutes severe obstacles for the profitability for the Bakken.
  • In a scenario where no wells were added post 2017 and the wellhead (at WH) price remained at $40/bo [~ $50/bo WTI] estimated losses for the project would be $20 – $22 Billion.
  • In a scenario where no wells were added post 2017 and the wellhead price remained at $60/bo [~ $70/bo WTI], the payout was reached after 7,5 years (in 2025) and the estimated return for the project becomes 3,5%.
  • With a sustained wellhead price at $74/bo [~ $84/bo WTI] post 2017, the payout was reached after 4,3 years (in 2022) and the estimated return becomes 7%.
    What makes the profitability for the Bakken challenging are the number of years front loaded with negative cash flows.
  • So far the recent years improvements in flow and Estimated Ultimate Recovery (EUR) have not entirely caught up with the decline in and the sustained lower oil price.
  • For the average 2016 vintage well it was estimated that a sustained oil price of $53/bo at WH [~ $63/bo WTI] would return 7%.

    Figure 01: The chart above shows the estimated rolling 12 months totals [black columns] net cash flows. The red area shows the estimated cumulative net cash flow since Jan-09 and per Jul-17. 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 has been in force. Price of oil, North Dakota Sweet (NDS) and realized gas price as reported by several companies.

In the Bakken(ND) and since January 2009 and per July 2017 an estimated $100 Billion has been used for manufacturing operational LTO wells and at end July 2017 an estimated $35 Billion were outstanding to be recovered from the estimated remaining proven developed producing (PDP) reserves.

At the most CAPEX for well manufacturing in the Bakken out spent cash flow from operations at an annual rate of $9 Billion. For the Bakken there has been two distinct CAPEX cycles, the first in 2011/2012 while the oil price remained high, followed by another in 2015 after the collapse in the oil price.

The second cycle may have been rationalized by several factors like an expected rebound in the oil price, which OPEC (primarily its Middle East members) helped derail through their rapid increase in oil supplies starting in early 2015 in an (believed) effort to fight for market share. The second cycle may also have been rationalized by the incentive structure for management of LTO companies in which these were rewarded by volume growth over profitability.

Incurred costs for drilled, uncompleted wells (DUCs) and salt water disposal wells (SWDs) are not included. Directors cut for September 2017 listed 889 wells waiting for completion. Costs from any heavy and costly well maintenance/interventions are not included.

The DUCs represents $2,2 – $2,7 Billion in capital employed.

For the Bakken as one big project and the life cycle analysis the gross interest costs of 6% were reduced by 35% to reflect corporate tax effects.

Effects from hedges and from bankruptcy proceedings (debt restructuring) are not included.

Any arbitrage from the realized oil price adjusted for wellhead price, transport costs and any tax effects from this arbitrage are not included.

Some companies are now recirculating primarily borrowed money (at some interest) from the net operating cash flow and injecting additional capital  to continue the manufacturing of new wells.

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Written by Rune Likvern

Sunday, 8 October, 2017 at 19:26

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

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