Fractional Flow

THE BAKKEN, A SNAPSHOT FROM 40 000 FEET AS OF END 2020

NOTE, this article is split into two parts.

The first part, the main body (5 500 words [includes text for charts and tables]), presents this analysis’s results.

The second part, supplemental information and documentation (3 000 words [includes text for charts), lists data sources, describes methods, abbreviations, acronyms, and some of the terms used in this article.

This analysis is a snapshot of Light Tight Oil (LTO) extraction in the Bakken in North Dakota (ND) treated as one big project with actual data starting in Jan-09 and a cut-off Dec-20.

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Proven reliable methods on the Estimated Ultimate Recovery (EUR) for any well (or for the average well of specified vintage populations, plays, fields, companies, or other) is crucial to make estimates on remaining Proven Developed Producing (PDP) and Proven UnDeveloped (PUD) reserves which are the linchpins for assets backed lending (reserves-based lending).

EUR assessments based on realistic decline curves are the foundations for realistic forecasts on future cash flows, which form the basis for the companies’ financial planning, inclusive CAPital EXpenditures (CAPEX) for future well additions, and gatherings and processing systems.

Reserves-based lending is what the companies depend on to leverage their equities, inclusive owners’ capital for loans that together set the pace for developments of their acreage. These loans often come with clauses about the speed for drilling the companies’ area as the lenders want to see their capital returned with a profit within an agreed time frame. These loans come with covenants of various scopes commonly described by financial metrics, which the borrowers have accepted to honor.

In this article, I will focus on PDP reserves as there is more uncertainty associated with developments of PUDs in time, price, and cost.

This Bakken article uses the same comprehensive and granular analysis of the average EUR by vintage and developments for PDP reserves and R/P for the Bakken presented in the article Bakken, Something About EURs, PDP Reserves and R over P Ratio in January 2020.

***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 Dec-20. 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’ annual and quarterly reports.

NOTE; the chart in figure 1 shows an estimate (red area) on the development of total capital employed (equity and borrowed) (from Jan-09 to Dec-20) for the manufacturing of wells that needs recovery before profits.

The high use of inorganic funding in 2020 is due to a combination of the collapse in the oil price and companies curtailing production to reduce costs and supplies as a contribution to rebalancing the market faster.

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

Apply caution from generally projecting results presented in this article on companies.
For public companies, the best insights are derived from their SEC filings, researching theirs well population’s actual performances (like over at Shaleprofile.com) and applying some alternative proven metrics derived from existing data.

The rapid build in the Bakken LTO extraction, refer to figure 3, came in two cycles, the first from early 2009 to early 2015, resulted from heavily outspending cash flows from operations. A considerable portion of it was debt. This massive inorganic funding boosted production and cash flows from operations. The second cycle started in early 2017 and ended in late 2019 was, to a lesser extent, inorganic funded.

The relative increase in the decline rates for younger vintages, see figures SD 02 and SD 06, explain why the companies must remain on the treadmill to bring in many new wells to sustain/grow the production. More importantly, sustain/build their PDP reserves, which are the significant component for reserves-based lending.

The Prices of USD, Oil, and U.S. Fiscal and Monetary Policies

Oil is priced in U.S. Dollar (USD or US$); therefore, the oil price becomes strongly linked to fluctuations to the strengths and weaknesses of the USD. The USD is the world’s dominant reserves currency, and changes to its exchange rate are closely linked to the monetary policies of the U.S. Federal Reserve (the Fed in short), and the U.S. fiscal policies.

The Fed has a monopoly for controlling the volume of USD (Federal Reserves Notes, FRN) in global circulation.

In reading this article it is imperative to understand the differences between monetary policies, and the monetary system.

The oil (or energy) system is one or several subsystems embedded in the global financial matrix, and monetary and fiscal policies thus influence the oil’s price formation.

The sequence and interdependence of these activities are.

Changes to total credit/debt ==> Changes to energy consumption ==> Changes to GDP

For all practical purposes, this article documents that these activities in recent decades were perfectly correlated.

World GDP (PPP) and world energy consumption have been 99% correlated during the last 4 decades, refer also figure 04.
World economic activity is commonly expressed as changes to Gross Domestic Product (GDP expressed in USD PPP), and in recent decades this has been 98% correlated with changes in world total credit/debt (expressed in USD market value), ref also figure 06.

In short, this means that economic growth (growth in GDP) for several decades has and still is dependent on borrowing from the future (continue growth by taking on more credit/debt) and pull demand forward in time.

As countries, corporations, and households approach debt saturation, growth in credit/debt will slow, which will weaken the so-called credit impulse and economic growth.

Debt saturation; maxed-out balance sheets cannot accommodate more credit/debt. The entity cannot service more credit/debt as additional credit/debt offers diminishing returns with little or no stimulative effect on the economy.

Lowering interest rates allowed for growth in total credit/debt, and gradually a more significant portion of the income becomes allocated to service the growing debts unless income grows as fast or faster.

***Figure 01:*** The chart above shows the oil price (Brent spot FOB) [black line and rh scale] together with the credit impulse for the 43 economies that in 2019 represented about 84% of the world’s Gross Domestic Product (GDP in PPP) [red line and lh scale].
The numerator is the second derivative of YoY changes to total private and public debt, while the denominator is the GDP.
The rationale for including YoY changes in public deficits/surpluses is that they add or subtract aggregate demand.

Figure 1 illustrates the close associations between movements in the oil price with changes in the credit impulse.

I would argue to include public deficits/surpluses when calculating the credit impulse. Public deficit spending adds to aggregate demand.

The high in the oil price during the summer of 2008 happened while the USD was weak.

Towards the end of QE3 in 2014, the USD started to strengthen versus most other currencies (refer also figures 13, 15, and 17).

One significant contributor to the spike in the oil price in 2008 was that investors would rather hold something tangible instead of the rapidly weakening USD, refer also figure 02.

Investors wanting out of their oil positions may partly explain the unprecedented collapse in the oil price of more than USD 100/Bo over a few months in the second half of 2008.

The high investments in U.S. Light Tight Oil (LTO) extraction continued after the collapse in the oil price in 2014 based on expectations of a sustained higher oil price. The effects of a weaker USD and high global credit/debt growth appears poorly recognized.

In 2016 a new round with high global credit/debt growth helped support a renewed increase in the oil price. This credit impulse came to an end during Q1-2018, and the oil price collapsed again in Q3-2018. The USD appreciated (higher DXY) significantly since the end of 2014.

***Figure 02:*** *The chart above shows the developments in the oil price (Brent spot) versus the U.S. Dollar Index (DXY) from Jan-00 to Sep-20.*

The correlation calculations between the oil price and the DXY for Jan-00 to Sep-20 came out at 0,78.

Oil (and several other commodities) priced in USD has an inverse correlation with the USD index (DXY), and the strength of this correlation is not stable.

In figure 02, and for what it is worth, note that the oil price did not move above USD 100/Bo when the DXY was above 90.

Figure 13 shows that the oil price was high and inversely correlated with (DXY) from Jan-11 to Sep-20 (this is somewhat deceptive and will be documented below in this article).

Many other factors influence the oil price, like supply/demand balances, the ebb and flow of speculative momentums, perceptions of future economic developments, changes to consumers’ affordability, and stock levels.

This article will focus on the associations between the oil price, oil supplies (crude oil and condensates; C+C), and the DXY.

The rapidly growing DXY leading up to the oil price collapse in 2014 was a more dominant factor in the collapse of the oil price than the strong growth in U.S. Light Tight Oil (LTO) extraction followed by the increased supplies from OPEC, refer also figures 13, 15 and 16.

In recent decades there has been an exponential growth in world aggregate credit/debt (see also figure 05), which fueled economic growth that commanded an increase in oil/energy consumption (this includes the rapid growth in so-called renewables like solar and wind).

The growth in global credit/debt and a weaker USD combined with low-interest rates in the U.S. allowed for periods with higher USD denominated oil prices partly funded by an increase in external US Dollar-denominated debt now estimated at around USD 13 Trillion.

The increased borrowing from the future allowed for many improvements in living standards and higher wealth accumulation.

Bakken, Something About EURs, PDP Reserves and R over P Ratio

Proven reliable methods on the Estimated Ultimate Recovery (EUR) for any well (or other agreed parameter like EUR for the average well of specified vintage populations for plays, fields, companies or other) is crucial to make estimates on remaining Proven Developed Producing (PDP) and Proven UnDeveloped (PUD) reserves which are the linchpins for assets backed lending (reserves-based lending).

Attainable EURs with realistic decline curves are also the foundations for reasonable estimates on future cash flows, which forms the basis for the companies’ financial planning inclusive CAPital EXpenditures (CAPEX) for future well manufacturing.

Reserves-based lending is what the companies depend on to leverage their equities inclusive owners’ capital for loans that together sets the pace for developments of their acreage. These loans often come with clauses about the speed for the drilling of the companies’ area as the lenders want to see their capital returned with a profit within an agreed time frame. These loans come with covenants of various scopes commonly described by financial metrics which the borrowers have accepted to honor.

In this article, I will focus on PDP reserves as there is more uncertainty associated with developments of PUDs in time, price, and cost.

This article is based on a more comprehensive and granular analysis of the average EUR estimates by vintage and developments for PDP reserves and R/P for Bakken than what was presented in the article “The Bakken, a little about EUR and R/P” in August 2016.

A low R/P ratio (index) gives expectations of a steep decline in extraction from the growing population of wells, which results from Light Tight Oil (LTO) wells had steep and now steeper initial declines. The steeper declines also explain why the companies must stay on the treadmill to bring in a high number of new wells to sustain/grow the production and, more importantly, sustain/build their PDP reserves, which are the significant component for reserves-based lending.

This study estimated remaining Proven Developed Producing (PDP) reserves in the Bakken(ND) as of end Oct-19 for the reference case to 1,6 – 1,7 Gbo (Giga, billion barrels).
The PDP reserves are from all the more than 14 000 horizontal wells started from Jan-08 and per Oct-19.
The EURs for the average well of the 2008 – 2019 vintages used in this study are shown in figure SD 6 at the end of this article.
As of the end of Oct-19, the R/P (for Bakken, ND) was estimated at 3,3 (reference case).
A sensitivity analysis adding 5% to EURs for the 2015 – 2019 average vintage wells increase the R/P to 3,5.
This study Juxtaposed the PDP estimates with the PDP numbers from the SEC 10-K filings for 2018 for some public companies that are heavily exposed to the Bakken (more than 90% of their equity/entitlement production from the Bakken).
At the end of 2018, this study found that these companies’ SEC reported PDP reserves were overstated with 30% – 50%.
An independent verification confirming overstated reserves would, for those affected, likely result in a downgrade of their credit rating. A downgrade to below investment grade would have far-reaching consequences as any institutional investors would be forced to sell their bonds into a liquid starved junk bond market, and the companies would be faced with much higher interest rates for debt that is rolled over which eats into their cash flows.
Should several independent and seasoned third parties verify the magnitude of overstated reserves, several LTO companies would be cornered, and the only way to paper over this would be to sweat it out while praying for a significant lasting higher oil price (like $90/bo or higher) soon.
Cornered because any sale of a significant portion of their well portfolio to buyers that have done their due diligence based on actual well data could come up with a much different assessment from the seller’s reserves and asked price based on the seller’s booked value of the portfolio for sale. A realized sale of a significant portion of the well portfolio reflecting the buyer’s offer could highlight that the seller’s booked to model PDP reserves is much lower. A realized sale could force the seller to take considerable impairments, which subsequently would raise questions about the remaining PDP reserves on their books. And as the PDP reserves of one or several companies become questioned, more would follow.
Based on the PDP reserves from this study, it was estimated that each barrel of oil in the ground was burdened with about $30/bo (includes revenues from natural gas) to recover employed capital.
Another way to put this is that each barrel of oil has to netback $30/bo at the wellhead, or gross about $55 – $60/bo at the wellhead to recover employed capital (owners’ capital and debt) and also pay for Plugging & Abandonment. The estimated $55 – $60/bo is to recover employed capital and thus leaves no profit.
Applying simple project economics to earn a return of 7% (for the Bakken as one big project) would require an oil price of $80/bo at the wellhead for the PDP reserves as of end Oct-19.
Management in many shale companies has a performance incentive structure in which production developments has been/is dominant.
For the next 1-2 years, managements of LTO companies will generate and implement strategies that search to balance allocation of available capital to sustain and/or grow their production and reserve base (used for reserved based lending), deleverage and/or pay dividends to a growing number of impatient owners.
To exacerbate this challenge, the banks now have tightened requirements on revolving credit, decreased their loans, and voiced concern that the assets of some shale companies will not cover the loans. This is commonly referred to as balance sheet/accounting insolvency, and if the situation continues, creditors and lenders could force the company to sell assets or declare bankruptcy.
At present oil/gas prices this becomes exquisitely balancing acts as any financial deleveraging and dividend payouts eat into funds that otherwise could be made available for more well manufacturing.
Reducing CAPEX for well manufacturing below some threshold to generate some Free Cash Flow (FCF) comes with some catches, and this is not only from the prospects from a decline in production/extraction and thus operational cash flow.
Changes to the Reserves Replacement Ratio (RRR) is an important parameter to follow and how it affects PDP reserves. Many companies have relied heavily on reserves-based lending, and a significant decline in PDP reserves will, by default, increase financial leverage and may (stress) test some of the loan covenants.
Covenant light loans give less protection for investors. Credit rating agencies flagged problems with these for years, and issues with leveraged loans can happen overnight as it is challenging to see stress building on balance sheets from inflated (oil and gas) reserves estimates.
Realistic EURs and R/P estimates (produced by competent and independent third parties) could become a real game-changer for the future pace of US LTO developments.
In recent years I have come to use the global credit impulse as one of the major leading indicators to predict the band of the oil price one year forward. Back in August 2018, I used the global credit impulse (amongst several other indicators like supply and demand, storage, etc.) to predict the oil price one year forward.
As of now and for 2020, few things suggest the global credit impulse will give support for a material higher oil price. Then throw in the US presidential election in 2020, which now makes me extend my price band of $55 – $70/bo from late 2018 for Brent Spot for this year.
OPEC+ may cut more to supplies to shore up the oil price, but OPEC+ has no control over changes to the global credit impulse, the future strengths/weaknesses to the US$, and developments in affordability amongst the global consumers.
In 2019 an average oil price in the mid-’60s (Brent Spot) triggered protests amongst consumers in several economies. There is a limit to how much higher the oil price for struggling US consumers can rise before it starts to affect consumption. The affordability threshold in recent years has declined with the higher and continued growth in total global debt.

My expectations for the oil price for 2020 are in line with most other analysts, and if that comes true, LTO operators should not expect much financial relief from the oil price this year.

Figure 1 Bakken split produced and PDP Oct 19 — **Figure 1:** The chart above with stacked areas shows the development in total produced (red area) and total Proven Developed Producing (PDP) reserves (blue area) from Jan-08 and per Oct-19 [rh scale]. The black line is the price of North Dakota Sweet (or Williston Sweet) [lh scale].

Figure 1 shows that since early 2015 and through the slow down till early 2017 and per Oct-19, the remaining Producing Developed Remaining Reserves (PDP) for the Bakken has remained almost flat. In other words, reserves were extracted/produced at about the same rate flowing wells were added.

LTO extraction grew from 0,92 Mbo/d in Jan-17 to 1,43 Mbo/d in Oct-19 or close to 60%.

In the same period, PDP reserves grew with an estimated 90 Mbo or about 6%.