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%.
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.