Only 1% of the Bakken Play area is commercial at current oil prices. 4% of horizontal wells drilled since 2000 meet the EUR (estimated ultimate recovery) threshold needed to break even at current oil prices, drilling and completion, and operating costs.

The leading producing companies evaluated in this study are losing $11 to $38 on each barrel of oil that they produce, the very definition of waste.

Although NYMEX prices are about $46 per barrel, realized wellhead prices in the Bakken are only $30 per barrel according to the North Dakota Department of Mineral Resources. At that price, approximately 125,000 acres of the drilled play area of 10,500,000 acres is commercial (green areas in Figure 1).

Figure 1. Bakken Shale Play commercial area map at $30 per barrel wellhead price. Contours are in

barrels of oil estimated ultimate recovery. Contour interval = 200,000 barrels of oil.

Source: Drilling Info, North Dakota Department of Natural Resources & Labyrinth Consulting Services, Inc.

(click image to enlarge)

The break-even per-well EUR is 700,000 barrels at a $30 oil price. The underlying economic assumptions are shown in Table 1.



Table 1. Economic assumptions and outcomes used to determine the Bakken $30 per barrel commercial area shown in Figure 1.

Source: Company presentations and Labyrinth Consulting Services, Inc.

(click image to enlarge)

There has been much debate about the break-even price for tight oil plays in the U.S. This discussion is largely meaningless because there is no single break-even price for any play.

Break-even price depends on EUR and every well has a different EUR. EUR depends on reservoir geology and geology varies geographically.

Drilling and completion technology cannot make up for bad geology. An area with poorer geology costs more to produce and will never perform as well as an area with better geology. And technology comes at a price. Longer laterals and more frack stages mean that a higher EUR is needed to to pay out the additional costs.

Leading Operators Analysis

I evaluated the leading operators in the Bakken Shale Play based on the greatest number of operated wells and highest cumulative oil production. The companies evaluated were Continental Resources (CLR), EOG Resources (EOG), Hess Corporation (HES), Marathon Oil Corporation (MRO), Statoil (STO), Whiting Petroleum Corporation (WLL) and XTO Energy Inc. (XTO), a subsidiary of ExxonMobil.

I used standard rate vs. time decline-curve analysis to forecast EUR for wells with first production in 2010 through 2014 and then calculated a weighted average-well EUR for each operator based on the number of wells for that operator in each production year (Table 2).



Table 2. Summary of evaluated operator EUR by year of first production and the weighted average

well EUR based on the number of wells in each production year.

Source: Drilling Info and Labyrinth Consulting Services, Inc.

(click to enlarge image)

Table 3 shows the ranking of the evaluated operators by weighted-average oil EUR for all years evaluated, and the break-even realized oil price at that EUR.



Table 3. Weighted average EUR ranking of the evaluated Bakken operators, the number of

producing wells in the analysis and the break-even realized oil price at that EUR.

Source: Drilling Info and Labyrinth Consulting Services, Inc.

(click to enlarge image)



Average well EUR among top operators in the Bakken ranges between 312 and 513 MBO (thousand barrels of oil). The associated break-even oil prices range from $41 to $68 per barrel. Marathon has the highest EUR per average well and Whiting has the lowest among the evaluated companies. This is a considerable spread of EUR (64%), and the spread among the top 3 operators–Marathon, Statoil and XTO–is also considerable (32%).

Break-even prices (Table 3) are inversely proportional to EUR. Marathon’s break-even oil price is $41 per barrel while Whiting’s is $68 per barrel, the same percentage spread (64%) as for EUR before the effects of rounding shown in the above tables.

The weighted average break-even price for these 7 operators is $61 per barrel but, clearly, there is no single break-even oil price for the Bakken or any other play.

I compared the EURs in this study with company claims from investor presentations (Table 4–not all companies state an average Bakken EUR).



Table 4. Comparison of Berman best-year estimated ultimate recovery (BOE–barrels of oil equivalent using a 6 MMcfg:1 BOE conversion factor for gas) with company average EUR (BOE).

Source: Drilling Info, Company investor presentations and Labyrinth Consulting Services, Inc.

(click to enlarge image)



The differences are not large. Except for EOG, however, I was unable to match my best-year forecasts with a near-recent year claim by the companies. Look carefully at company claims. They often use an EUR that they anticipate in the future or that is from a limited area. For example, Continental uses a “target” Bakken EUR of 800 MBOE for 2015 despite the fact that their stated average for 2014 was only 550 MBOE (70% of the target EUR). The highest average EUR that I forecast for Continental is 470 MBOE (for 2011 in Tables 2 and 4).

What It Means

How should we understand the variance in EUR and break-even prices among the evaluated companies?

I believe that the different average-well EUR among companies reflects geographic changes in geology. This is mostly expressed in reservoir quality for the Bakken. Because the geology varies, better and poorer geology is embedded in the location of positions that the various companies acquired when they entered the play (Figure 2).



Figure 2. Location map of wells operated by the companies evaluated in this study.

Source: Drilling Info and Labyrinth Consulting Services, Inc.

(click to enlarge image)



Sweet spots are found and not predicted. They are evident only after thousands of wells have been drilled and produced for some time. By then, all land has been captured. A company has to work with the position it was able to acquire in the land grab that characterizes shale plays.

Late entrants like Statoil in the Bakken or Devon in the Eagle Ford pay a premium to buy into an existing sweet spot. The failure of a late entrant like Shell in the Eagle Ford resulted from paying a premium for a position outside the sweet spot.

There are no significant differences in technology or operator competence among the companies evaluated in this study. Technical success in the Bakken is largely based on luck in the initial selection of a lease position.

The manner in which operating companies have managed their production growth, cash flow and balance sheets, however, differs considerably and is based on choice and not on luck. Figure 3 shows key financial data for companies evaluated in the Bakken Play.



Figure 3. Capital expenditures-to cash flow and debt-to-cash flow ratios for evaluated companies. Source: Google Finance and Labyrinth Consulting Services, Inc.

On average, the evaluated companies spent more than double their cash flow on drilling and completion (capex) in the first half of 2015. In other words, they lost more than a dollar for every dollar they earned. Companies like Whiting and Marathon outspent cash flow by a factor of more than 3-to-1 while a company like XTO (ExxonMobil) earned more than it spent.

Evaluated companies’ debt-to-cash flow ratio averaged 6.3. This means that it would take more than 6 years to pay off their debt if all revenue were used for that purpose. Many banks use a debt-to-cash flow ratio of 2.0 as the threshold for calling loans (debt covenant). The E&P industry’s average ratio from 1992 to 2012 was 1.58 (also see Assessing Systemic Risk With Debt to Cash Flow).

Every company evaluated in this study, therefore, is in the danger zone as far as banks are concerned. Marathon and Whiting have debt-to-cash flow ratios of 5 times greater than the threshold of 2.0, while EOG, Statoil and XTO are at least below the average for this group of companies.

A continuation of low oil pricing may have profound and negative implications for Whiting, Marathon, Hess and Continental based on this financial performance data.

Conclusions

Tight oil is expensive to produce. The biggest increase in Bakken production occurred after oil prices reached more than $90 per barrel in 2011 (Figure 4).

Figure 4. Bakken oil production and CPI-adjusted WTI oil prices (August 2015 dollars).

Source: Drilling Info and Labyrinth Consulting Services, Inc.

(click to enlarge image)



Since oil prices collapsed in 2014, capital and operating costs have fallen almost as much as product prices. Lower costs, hedges, a price rally to around $60 per barrel from March to early July 2015, and continued availability of outside capital have allowed most producers to survive. Higher-priced hedges are running out and service company costs cannot fall much further without bankrupting those companies. Also, I do not believe that efficiency gains are significant going forward.

All Bakken producers in this study can break even at $60-70 per barrel wellhead oil prices at current low drilling and completion costs. At $30 realized prices, they are all in serious trouble. Their investor presentations give little sense of how perilous their situation is in this price environment.

The path forward is uncertain. I expect even lower prices in coming months as the only logical market response to a persistent over-supply of oil in the world and a weak global economy. The principal unknown is whether or not the world’s over-supply of capital will continue to favor investment in U.S. tight oil considering its poor and worsening financial performance.

Bakken oil production has fallen only 26,000 barrels per day since its peak in December 2014 and the number of producing wells reached an all-time high of 12,940 in July. This makes no sense at all given the economics of $30 oil.

If producers cannot change their behavior and demonstrate discipline in their spending, the market will do it for them with much lower oil prices.