What do you do when you are $300 billion in the red?

U.S. shale and Light Tight Oil (LTO) may not be your thing, but it's part of the reason why many of us in the oil and gas industry, or energy transition sector, have a bit more time on our hands at present.

This article (Part 1 of 2) provides insights into the second largest and oldest of LTO plays, the Bakken. Recent production data suggests the Bakken is leading the way and going 'where no shale play has gone before', but is it going in the right direction?

In a research note in April 2020 entitled the Great Compression, Deloitte estimated the entire U.S. shale industry registered net negative free cash flows of $300 billion, impaired more than $450 billion of invested capital and saw more than 190 bankruptcies since 2010. Continuing low oil prices have forced producers to adopt a raft of measures to reduce their costs, here are few more recent and noteworthy examples;

• In April 2020 Whiting filed for Chapter 11.
• In May 2020, Continental Resources, which has limited price hedging in place, announced that it had shut in 70% of their production.
• In June 2020, one of the pioneers of the shale revolution Chesapeake Energy filed for Chapter 11 protection.
• In August 2020 Equinor announced that it will stop further shale drilling in 2020.
• In September 2020, Japanese trading house Sumitomo Corp, have called time on US shale, having announced that it is selling it's entire stake in Marcellus shale gas project.
• In September 2020, Oasis decided to enter into a 30-day grace period for paying the delayed interest that was due Sep 15, 2020. The company owed interest on its 6.875% Senior Unsecured Notes due 2022 and 2.625% Senior Unsecured Convertible Notes due 2023.
• In September 2020 Whiting announced it had exited Chapter 11 decimating it's share holders (Whiting's old shares were exchanged for new shares at a 75 to 1 ratio).
• Today, September 28th 2020, Devon to Buy WPX After Permian Investors Push for More M&A.

As Rachel Adams-Herd of Bloomberg mentions in her article of June 2020; 'America’s shale revolution grew out of a well-orchestrated dance. For almost a decade, producers wooed investors by touting rosy estimates of how much crude oil they could profitably drill, and investors forked over money. That ended last year, even before the global pandemic sent oil prices tumbling. Investors, after years of meagre returns, began demanding that shale companies stop marketing mythical future barrels that would never earn a dollar.' Bloomberg recently reported that Mike Lister, a JP Morgan energy banker, estimated that banks wrote off approximately $1 billion in reserve based loans for shale companies in 2019, exceeding their total losses for the past 30 years, and that trend is continuing.

So what actions are shale producers taking and who are best placed to survive? Raw Energy in their articles from January 2020 set out the results of borrowing base reviews, debt maturities and financial and operating metrics for producers. It also outlines the actions companies often take to deal with debt, particularly in restructuring situations (the so called Playbook).

The Playbook comprise at least 16 possible actions; looser terms with existing lenders, sell unsecured debt, create additional first/second/third line debt, sell assets, create joint ventures, reduce capex, reduce Lease Operating Expenditure (LOE), reduce General & Administrative (G&A) costs, sell existing derivatives to raise cash, repurchase debt at a discount, debt for debt exchanges, debt for equity exchanges, sell equity, retain financial/restructuring advisors, merge with another company.

Simon Todd of Capriole Energy in his article entitled 'Caught in a trap' outlined what an ideal company would look like in terms of future cost performance. He also proposes Shale Bank: a business model and plan to optimize recovery from bankrupt US E&P assets.

So, have we reached the end of the debt restructuring process? As Winston Churchill famously said; ' Now this is not the end. It is not even the beginning of the end. But it is, perhaps, the end of the beginning'.

In this article we review the production performance, reserves and net present value of wells that started producing from 2008 onwards in the North Dakota part of the Bakken and Three Fork Light Tight Oil (LTO) play. The study provides lenders and financial institutions with an independent analysis of the second largest U.S. LTO shale play. These insights may help determine possible strategies for producers, investors and lenders. In Part 2 we compare the performance of three major Bakken producers; Whiting Petroleum, Marathon Oil and Hess.

So is there a future for mature shale plays such as the Bakken or has the sun finally set on them? The results from this study demonstrate that that with current production levels oil prices of $63 (WTI) or more are required to generate healthy returns (IRR 15%) in the Bakken and $50 to breakeven. This is an average across the entire play and it assumes a full cost model that includes certain costs typically excluded by producers and some analysts. There is a wide range in oil prices required to generate IRR15% between producers. Producers with the best positions in the 'core' such as Marathon Oil, ConocoPhillips and WPX can generate reasonable returns (IRR15%) at around $50 WTI.

As the oldest of the U.S. shale plays the Bakken is leading the way and going where no shale play has gone before. There are clear indications that the current mean 24 month oil produced, a key economic metric, has started to decline (2018-2020). This is not unexpected and is typical of late stage field performance. The lower rates are a response to tighter well spacing (including parent-child behaviour), lower reservoir pressure (and hence energy) and the onset of the bubble point (as indicated by the significant increase in GOR and water cut). The decline in the average 24 month oil produced is clear, the future rate of decline is uncertain. The ability of producers to withstand the combined effects of declining production and sustained low oil prices is also uncertain.

Therefore historical well spacing and stimulation programmes will no longer be appropriate or optimal to develop the remaining recoverable resources.

So what do you do when you are $300 billion in the red? Keep spending - but spend wisely and efficiently, pray for $63 WTI or more (in the case of the Bakken), adapt your well completion and spacing programme to the new realities and most importantly listen to your geologists and engineers.

Be advised that this analysis and the opinions expressed are those of Nolan Geoscience, and the data in the charts and the text are created by Nolan Geoscience from public sources such as company press releases, financial reports, etc. No specific investment recommendations are made in this article, and readers should perform their own research and due diligence before making an investment decision.

Thanks to ShaleProfile and Enno Peters for access to the Shale Analytics platform and database.

1. Executive Summary

The Bakken and Three Forks accounts for 17% of total U.S. shale oil production. The results from this analysis suggest the current discounted cash flow of the 15,183 producers (wells drilled since 2008 in the North Dakota part of the Bakken) is minus $45 billion as illustrated in the figure below. The current total loss of the entire Bakken is likely to be closer to minus $50 billion. The estimate is in line with the Deloitte analysis and has been compared with other Discounted Cash Flow (DCF) models. The flattening of the curve since 2016 is related to the combined effects of increased 24 month oil and lower capital and operating costs.

The DCF model was built with the help from colleagues at Bloomberg, Tudor Pickering Holt and Woodmac. Comparisons were also made with the new well economics dashboard available in ShaleProfile. One of the main sensitivities is around cost assumptions - what costs to include / exclude. Two cost scenarios are considered in the economic model.

Oil prices required to breakeven / achieve IRR 15%

The chart below shows the average 24 month oil and gas produced by year versus the WTI breakeven price (red dots) and the WTI price required to generate IRR15% (blue dots). As outlined below 24 month oil produced is a key economic metric. The results from this study suggest that with current production levels the mean breakeven oil price for the Bakken (assuming a full cost model) has dropped from $99 WTI in 2012 to $50 WTI in 2020. To generate an IRR of 15% the WTI oil price required has dropped from $136 in 2012 to $63. Therefore on average (assuming a full cost model) the Bakken requires prices of $63 WTI or more to generate a healthy profit. The drop in price required to make a profit since 2012 is related to the combined effects of increased 24 month oil produced and lower capital and operating costs. It's important to note the 2019 and 2020 24 month numbers are estimates.

24 month oil is a key metric - why?

The figure below is a key one in terms of the direction of future production. It shows mean North Dakota Bakken / Three Forks oil production by year normalised to 2010 production, this allows the growth/reduction in production since 2010 to be better visualised. Note the areas high lighted by 1 and 5 on the graph. Higher rates in 0-24 month period for later years primarily related to improvement in completion technology. 24 month oil has a strong correlation with full cycle NPV and IRR. Initial rates (IP0) and 90 day rates have poor correspondence with full cycle NPV and IRR. The peak 36 month production occurs in 2017/2018. Note dramatic reduction in 12-24 month production for 2018 onwards. The trend appears to continues into 2020 but average production likely to be impacted by COVID-19 related production shut-ins. The lower rates are a response to tighter well spacing (including parent-child behavior), lower reservoir pressure (and hence energy) and the onset of the bubble point (as indicated by the significant increase in GOR and water cut).

Definition of the Bakken Core

A strong relationship between 24 month oil production and IRR can be established assuming other variables such as costs remain constant. The map on the left shows the WTI oil price required to generate 15% IRR for 2020 type wells, assuming a full cost model (the details of which are outlined later). Warm colours (red-pink) represent higher 24 month production and lower oil price required for 15% IRR ($40-54). The blue polygon is the Bakken Core area, as defined in this project. Note the location of 2019 and 2020 wells and strong correlation with areas of higher projected 24 month production performance and lower oil price required to generate 15% IRR.  

Producers with the best positions in the Core

The chart below shows the projected 2020 average 24 month oil and gas per well produced for the top 14 Bakken producers. 2020 24 month production is based on a 1.3 scalar of the mean 2016-2018 24 month production and in hindsight may be an over optimistic projection based on recent analysis. The future WTI oil price required to generate 15% IRR for 2020 mean wells for the full cost assumption is shown by the blue line and for partial cost assumptions it's the black line. Based on this analysis Marathon, ConocoPhillips and WPX can generate IRR15% or more at or above $45 WTI assuming full costs due to their superior core / sweet positions. Exxon (who bought XTO in 2009) and Equinor (who bought Brigham in 2011) have relatively high breakeven and IRR15% oil prices, but the Bakken is a very small part of their group production (2 and 3% respectively).

The true picture is of course more complicated as costs vary between operators. Determining Bakken operator cost becomes increasingly difficult as the proportion of Bakken production versus overall group production decreases.

Bakken EURs

Significant uncertainty and debate surrounds the terminal decline rate of producers and their associated Estimated Ultimate Recovery (EUR) values. EURs are a key component to determining reserves base lending.

Scott Lapierre addresses some of these issues in his article entitled 'On the Nature and Character of the Widespread Oil Production Shortfalls Reported by the Wall Street Journal' the Dmin Problem, a premature transition to constant rate decline (relative to a 3%-15% assumption), is a widespread occurrence. Additionally, the GOR Problem, an exponential increase in GOR, appears to correlate with - and often forewarn – the imminent onset of the Dmin Problem. 

Individual well EURs will be dictated by a variety of factors including terminal decline rates, oil price, minimum economic production rate required to cover lease operating expenditures (LOE), in order to maintain the well/pad and associated facilities. Work in this study suggests minimum economic rates between 5 and 10 bopd in the Bakken to cover these costs depending on oil price.

The figure below shows the oil produced versus the oil rate as per the slide above. It illustrates the uncertainties associated with estimating terminal decline rates and hence EUs in the Bakken. The interpretation below has average EURs increasing from 400 to 550 Mbo for oil from 2008 to 2019. For oil plus gas EURs have increased from 575 in 2008 to 785 Mboe (assuming a standard industry conversion of 6 mcf to 1 boe). These values are in line with the 20 year production estimates shown in the table in the figure below.

2. Location

The Bakken and Three Forks LTO play currently produces 1 of the 6 million bopd total US shale oil production. The play is within the Williston Basin and extends to Montana and Canada. The North Dakota part currently accounts for 98% of the oil production.

3. A brief history of the Bakken and Three Forks

The first Bakken discovery was made in 1953 after a well targeting the shallower Madison Formation along the Nesson anticline encountered oil in the underlying Bakken Formation. Conventional exploration along the Nesson anticline from 1950-1980s resulted in minor discoveries and fields. Between 1987-1999 attempts to exploit the Bakken with horizontal wells proved unsuccessful as these targeted the shale rather than the dolomite reservoir sandwiched between the shales. Geologist Richard Findley and Lyco Energy were instrumental in drilling the first horizontal well within the Middle Bakken reservoir section at Elm Coulee in late 1999. The horizontal section was fracced and resulted in a substantial increase in production that ultimately proved commercially viable. 

4. Comparison with Eagle Ford and Permian

Compared to the Eagle Ford and the Permian the Bakken has a higher 100 month oil production of 238 Mbo (versus 132 and 113). It has lower decline rates resulting in higher Estimated Ultimate Recoverable (EUR) per well - see the figure below. However, this is offset by a higher discount of Bakken oil and gas to West Texas intermediate (WTI) oil prices and Henry Hub (HH) gas prices. Up until recently limitations in pipeline capacity resulted in higher Bakken shipping costs.

5. Bakken Production 2008-2020: Peaked in 2018

The figure below summarizes 6 month, 24 month and 20 year production for 2008-2020 wells. The chart shows 24 month oil and gas production by year (in thousands of barrels oil and oil equivalent). Oil production peaked in 2018. Note 2020 production is projected to be similar to 2017 levels. Economics based on 20 year cut-off c. 20bopd

The figure below shows total North Dakota Bakken and Three Forks oil and gas production at the end of 2019 was nearly 1.9 million boepd. From November 2019 to May 2020 Bakken oil production fell from 1.46MM bopd to 0.83 MM bopd in response to low oil prices and Covid 19. Since May it has recovered to just over 1.0MM bopd. Typical with light tight oil shale plays, gas production has increased at a higher rate than oil. Gas production has grown from 10% in barrel equivalent production in 2012 to around 28% today. The standard industry conversion, based on energy content, is 6 to 1 (1 mcf) to (boe) i.e. six thousand cubic feet (6 mcf) = one barrel oil equivalent (1 boe). A conversion of gas to oil on value rather than energy basis is about 20 to 1 i.e. 20 mcf = 1 boe. Barrels oil equivalent (boe) is not a useful metric in terms of shale economics.

6. Increasing proportion of gas and water: more costs and less profit

The chart below illustrates the mean gas oil ratio (GOR) evolution by year from time of first production. Note lower rates with low to moderate increase in early years - versus later years with higher initial rates and subsequent steep rises in GOR. GOR evolution with time is consistent with drop in pressure, loss of energy in solution gas drive plays such as the Bakken and may be indicative of the onset of the bubble point.

The proportion of gas produced also varies by company depending on location and age of the producers. The map below shows the percentage of total 2016 – 2018 production that is gas - shown on the map to the left - as well as the location of 2016 – 2018 Oasis producers. The table shows the variation in percentage of gas production amongst the top 10 producers. Most companies are currently averaging 27-30%. WPX, Marathon and Slawson have lower percentages of gas (20-18%). Note Oasis has a higher gas percentage (38%) and this corresponds with a greater proportion of wells in the red and pink areas of the map representing gas percentage levels above 26%. Higher percentage of gas results in higher costs, lower revenue and lower IRR/NPVs.

Significant investment in gas gathering and distribution has been required in recent years. Unfortunately the return on gas, until recently, has been much lower than that for oil. Producers often exclude the significant costs for gas gathering and distribution in single well economics as these can be associated with a separate midstream entity.

Gas Flaring

The inability and/or reluctance to invest in additional gas gathering has resulted in an increase in the percentage of gas flared. This has grown from 10% in 2016 to nearly 20% today according to the North Dakota Pipeline Authority. According to SoEnergy, a company that specialises in flare gas recovery systems, that’s enough to heat every home in North Dakota for one month, 10 times over. It’s also significantly above the state’s 12% limit. Meanwhile, oil and gas companies continue to invest heavily in power generation, tying up precious Capex as they struggle to solve the gas flare challenge.

It's a similar story with water and the bed for increased water processing facilities. The figure below shows the average monthly variation in water cut by year for Bakken and Three Forks producers. Note the high initial water rate in first couple of months related to fraccing then drops and stabilises after clean up. Average initial water cuts have increased from 21% in 2008 to 52% in 2019. The increase in water cut is related to drop in pressure, increase in GOR, movement of the aquifer and onset of the bubble point. 

7. Political and Legal Uncertainties

a) What will happen to DAPL?

The Dakota Access Pipeline (DAPL) came onstream in 2017 with 520,000 bpd of capacity and was ultimately expanded to 600,000 bpd. It flowed close to full utilization for the major part of 2019 and Q1 2020. However, it did not completely eliminate rail exports as basin-wide production continued to increase and other pipeline options became less attractive. It is now the subject of a legal battle between Native American communities and the owners of DAPL who include Marathon, Phillips and Enbridge Energy Partners.

b) What will a Biden win mean for Shale?

According to an article in S&P Global Market Intelligence many of Biden's Democratic primary opponents pushed for a total fracking ban, including on private lands. Biden has promised only to halt new federal permits.

"I am not banning fracking," Biden said Aug. 31 during a campaign stop in Pittsburgh. "Let me say that again. I am not banning fracking — no matter how many times Donald Trump lies about me." Biden added that his $2 trillion clean energy investment plan held a place for oil and gas workers in western Pennsylvania. Even if Biden freezes federal permitting, some analysts see a muted supply impact as drillers shift focus to private acreage.

8. Who are the big Bakken Producers?

Companies with significant production growth since 2016 include Continental, WPX, Hess, ConocoPhillips & Marathon. The two majors, Exxon (who bought XTO in 2009) and Equinor (who bought Brigham in 2011) have maintained relatively flat production since 2016. In March 2020 Equinor announced that it will not drill any more shale wells this year. EOG were once a top Bakken producer and were instrumental in developing the play. Since 2014 EOG have pivoted their investment and focus away from the Bakken and into the Eagle Ford and Permian plays. EOG Bakken production has dropped from 98M BOPD in 2014 to 37M BOPD today.

The chart above shows the proportion of Bakken production versus overall group production for the major Bakken producers. Note the relatively high proportion for Whiting (95%), Oasis (91%) and Continental (72%) in contrast to Equinor (3%) and Exxon (2%).

10. The Bakken Core and Projected 2020 Production

Released production data from 15,183 wells (2008 onwards only, North Dakota only) were analysed by the author. Confidential/tight wells (1289 wells) were not included (wells can remain confidential/tight for a period of not more than 6 months). Well production data is from the North Dakota Industrial Commission (NDIC) and compiled by ShaleProfile.

Shown below are a series of maps and charts that show the evolution in 24 month oil by year from 2008. Red and pink colours on the maps and charts represent areas with greater than 260Mb 24 month oil. The chart show the distribution of wells by 24 month production and has the same colour scale as the map. Only wells that started producing in each year are shown on the maps. Note the increasing amounts of red and pink in the Bakken Core area (blue polygon) and the greater proportion of the graph occupied by red and pink in later years.

The final figures show an average for 2016-2018. The three maps below show the distribution of mean 24 month oil production, percentage of total production that is gas and the water cut for wells, that started producing between 2016 and 2018. These maps allow the definition of a core area within the blue polygon that has high 24 month oil (>260M bbls), lower percentage gas (in parts) and low water cut (<20%). Key fields within the Core include Parshall discovered by EOG in 2006, Sanish, Coulee, Antelope, Reunion Bay, Corral Creek, Hector, Myrmidon, Keene, Stony Creek and East Neeson to name but a few, in the McKenzie, Mountrail and Dunn Counties.

11: Well Spacing and Parent - Child Behaviour

The study does not go into detail on well spacing. Completion and spacing design is complex, producers and analysts commit huge resources to determining optimising both. After geology, well completion and well spacing (both vertical and horizontal) are the key factors determining well performance. Multi-well drilling from pads has facilitated the growth of parent - child well, where child wells, which are drilled near an original, i.e. parent well. Various multi-client studies have been undertaken on parent - child behaviour including; Enervus (formerly Drilling Info), Tudor Pickering Holt and EERC. In an article by Suzanne Edwards for Natural gas Intelligence in July 2019, Suzanne quotes James West, senior managing director of research at Evercore ISI.

'The positive parent-child well relationship was more common in the earlier days of the unconventional drilling boom when fewer wells were drilled per pad, and fewer fracture stages were implemented, West said. The less intense activity of the early days left wells “under-stimulated.”

However, as the age of mega-completions took hold around 2014 and a downturn in oil prices motivated companies to refracture wells instead of drilling new wells, the parent-child relationship turned negative as the wells were hyper-stimulated and shorter-lived.

Such mega-completions, where an operator may drill 20 wells per pad and implement 30 fracture stages for each one, are commonplace in most major shale formations in the United States, and are beginning to make their mark on the Bakken, West said.

Currently, there are still enough positive parent-child well relationships in the Bakken that operators can take advantage by refracturing the under-stimulated wells, West said.

Once the mega-completions strategy fully overtakes the Bakken in the near future, that parent-child well relationship will likely turn negative as it has in the Permian Basin, West said. At that point, Bakken operators may join operators in other formations in turning to technology and experimentation.

Newer technologies developed to mitigate parent-child well interference generally focus on one of two approaches, West said. The first uses chemicals that can absorb “frack hits” and better protect and insulate the parent well from the child wells. A frack hit is a cross-well interaction initiated as hydraulic fracturing solutions are injected into the ground.

The other method uses technology to “pin-point frack” the child wells, essentially forecasting more precise locations for child wells that may cause minimal interference with the parent well.

The Google Earth satellite image from May 2017 compares well paths from 2017 onwards in white and pre-2017 wells in black. It illustrates the move towards multi-well drilling from pads in later years.

12: Improvements in Production and Completion Technology

The EIA/IHS Upstream Cost Report from March 2016 summarises the benefits of multi-well pad drilling and how it allows for maximization of reservoir penetration with minimal surface disturbance. Operational costs are reduced, operators can check wellhead stats (pressure, production, etc.) on numerous wells in the same location. Pads are now being planned for 12, 16, or even 24 wells where there are multiple stacked zones. With the surface locations of wells on a pad being close to each other, mob-demob of rigs from one well to another is more efficient. Walking rigs, automated catwalks, and rail systems allow rigs to move to the next location in hours, not days. Facilities can be designed around pads, thus further reducing costs.

The slide below summarises the main development milestones in drilling technology since 1999. Of particular interest is the bottom chart which show the strong correlation between completion mean proppant mass and mean 24 month oil by year.

13. Debt to Equity of major Bakken Producers

The study does not go into detail on the financial health of Bakken producers but a guide is provided in the slide below which shows the debt to equity ratio of the major Bakken Producers as at June 17th 2020.

14: Economic Inputs

A discounted cash flow (DCF) model was built with the help from colleagues at a number of service providers including Bloomberg, Tudor Pickering Holt and Woodmac. Production profiles from this study were used as input. The resultant model was compared with those from three other companies and the results are broadly comparable. Comparisons were also made with the new well economics dashboard available in ShaleProfile. The main uncertainty and sensitivity is around cost assumptions - what costs to include / exclude. Two cost scenarios are considered full and partial. Separate models were built for average 2008-2020 wells and for 2020 P10-P90 type wells.

The table to the left is taken from a paper by Kleinberg et al at MIT Energy Initiative and MIT Sloan School of Management entitled Tight Oil Development Economics: Benchmarks, Breakeven Points, and Inelasticities. It highlights the differences between so called full and half cycle costs. Half cycle costs are often used by operators and these typically exclude finding costs, gathering, processing and transportation (GPT) costs, decommissioning costs and in some instances lease acquisition costs.

Economics for conventional oil and gas developments are closer to a full cost model including finding, lease and decommissioning costs. Many shale operators apply a Direct After Tax Rate of Return (ATROR) which exclude indirect capital items such as gathering, processing, midstream, land, seismic, geologic and geophysical costs. Modelling of operator economics shows this to be equivalent to the partial cost model used in this study.

Costs: EIA / IHS 2016 Study

The U.S. Energy Information Administration (EIA) commissioned IHS Global Inc. (IHS) to perform a study of upstream drilling and production costs in 2014 and published in 2015/2016. The IHS report assesses capital and operating costs associated with drilling, completing, and operating wells and facilities. The report focuses on five onshore regions, including the Bakken, Eagle Ford, and Marcellus plays, two plays (Midland and Delaware) within the Permian basin. The period studied runs from 2006 through 2015, with forecasts to 2018.

According to the report the onshore industry continues to evolve, developing best practices and improving well designs. This evolution resulted in reduced drilling and completion times, lower total well costs, and increased well performance. Drilling technology improvements include longer laterals, improved geosteering, increased drilling rates, minimal casing and liner, multi-pad drilling, and improved efficiency in surface operations. Completion technology improvements include increased proppant volumes, number and position of fracturing stages, shift to hybrid fluid systems, faster fracturing operations, less premium proppant, and optimization of spacing and stacking. Although well costs are trending higher, collectively, these improvements have lowered the unit cost of production in $/boe.

The Bakken play has consistently had the lowest average drilling and completion costs of the basins and plays reviewed in the IHS report. Improvement in drilling rig efficiency and completion crew capacity helped drive down drilling costs per total depth and completion costs per lateral foot, since 2012. Recent declines are partly a result of an oversupply of rigs and service providers. Standardization of drilling and completion techniques will continue to push costs down.

Full and Partial Cost Models

The figure below shows the historical costs for the full cost model and these are based on the EIA/IHS report, company SEC filings and quarterly reports for Bakken focused operators. Capex comprises lease acquisition, drilling, completion and abandonment costs. Opex comprises lease operating (LOE), gathering, processing and transportation (GPT) and general and administrative (G&A).

The figure above shows the assumptions for the partial cost model. Capex comprises drilling and completion costs only. Opex comprises lease operating (LOE) costs only. For 2020 is $6.5MM Capex and $6/BOE Opex.

Other Model Assumptions

Other model assumptions are outlined in the table below. These include a discount rate of 10% in all scenarios.

15. Economics: 2008 -2020 WTI Oil Price required to breakeven / achieve IRR15%

This figure above was shown earlier in the article and shows the WTI Oil Price required to breakeven / achieve IRR15% based on the production profiles outlined previously and full cost assumptions of $7.4MM Capex and $12.4/BOE Opex. It assumes constant oil price from time of first production, a discount rate of 10% and an economic life of 20 years. Other assumptions outlined in the table in the figure.

The figure below compares the Bakken breakeven WTI price by year for full and partial costs in this study with those of Rystad Energy summarised in a newsletter from December 2019. In the Rystad analysis WTI breakeven prices (which are calculated for every single oil producing well in ShaleWellCube) take into account drilling and completion costs, lease operating expenses, production taxes, royalties and overhead costs (transportation, price differentials and G&A). Production for each well is forecasted utilizing the best-fitting Arps model. Natural Gas Liquids (NGL) and gas prices are kept fixed at $15 per barrel and $2 per million British thermal unit (MMBtu), while the oil price is varied until the net present value hits zero. The annual discount rate is set to 10% in our calculation.

Note how the historical Bakken Rystad breakeven prices sit between the full and partial costs in this study.

The figure below shows the future WTI oil price required to breakeven (in red) for Bakken wells by year and is based on production profiles outlined previously and full cost assumptions $7.4MM Capex and $12.4/BOE Opex. Average wells assumed to start producing half way through the year (July 1st). Assumes historical North Dakota oil and gas prices, constant oil price from 2020, a discount rate of 10% and an economic life of 20 years. Other assumptions are outlined in the table in the figure.

High oil prices and relatively lower costs from 2008-2010 result in very low prices required to break even. 2011-2016 wells are unlikely to ever be NPV positive due to limited remaining production, higher costs and low historical oil prices at the time of production.

15: Company Comparisons: Marathon Oil v Hess v Whiting

Coming in Part 2 or contact me directly.

16. Conclusions

There are clear indications that the current mean 24 month oil produced, a key economic metric, has started to decline (2018-2020). This is not unexpected and is typical of late stage field performance. The lower rates are a response to tighter well spacing (including parent-child behaviour), lower reservoir pressure (and hence energy) and the onset of the bubble point (as indicated by the significant increase in GOR and water cut). The decline in the average 24 month oil produced is clear, the future rate of decline is uncertain. The ability of producers to withstand the combined effects of declining production and sustained low oil prices is also uncertain.

The results from this study demonstrate that with current production levels oil prices of $63 (WTI) or more are required to generate healthy returns (IRR 15%) in the Bakken and $50 to breakeven. This is an average across the entire play and it assumes a full cost model that includes certain costs typically excluded by producers and some analysts. There is a wide range in oil prices required to generate IRR15% between producers. Producers with the best positions in the 'core' such as Marathon Oil, ConocoPhillips and WPX can generate reasonable returns (IRR15%) at around $50 WTI.

As Raw Energy outlined in their articles from January 2020, producers will have to adopt a range of measures if they are going to survive. These include seeing looser terms with existing lenders, selling unsecured debt, creating additional first/second/third line debt, selling assets, creating joint ventures, reducing capex, reducing Lease Operating Expenditure (LOE), reducing General & Administrative (G&A) costs, selling existing derivatives to raise cash, repurchasing debt at a discount, debt for debt exchanges, debt for equity exchanges, sell equity, retaining financial/restructuring advisors, merge with another company.

Like any of the shale plays the Bakken has strengths and weaknesses and provides opportunities and threats. The figure below summarises them.

Acknowledgments

Thanks to ShaleProfile and Enno Peters for access to the Shale Analytics platform and database. Many discussions and help from colleagues currently and previously at Bloomberg, Woodmac and Tudor Pickering Holt. Thanks to Simon Todd of Capriole Energy for feedback.