Whiting Petroleum: Will Investments In Redtail Niobrara Or The Bakken Pay Off?

| About: Whiting Petroleum (WLL)


Economics of Redtail DUCs are compared to newly drilled wells there and in the Williston Basin.

Whiting may view EUR in Redtail relatively even more optimistically than in the Bakken.

Whiting's Redtail track record is compared to that of a leading operator in Colorado.

The outsized investment in Redtail Niobrara is likely a one-time event limited to 2017, as a sizable DUC inventory exists in Redtail, but not in the Bakken.

Completion of Redtail DUCs is essential to planned 29% production growth back to the level of Q4 2015.

Whiting Petroleum's (NYSE:WLL) massive CapEx plan for 2017 surprised the market. The plan calls for $420 million to be spent in Colorado's Redtail field and $580 million in North Dakota's Williston Basin. In the Bakken, the 2017 allocation represents a threefold increase compared to $182 million targeted for 2016. In Redtail Niobrara, a comparable rise by 158% is planned from 2016 level of $163 million. In this article, I will analyze the merits of capital expenditures in both locations, with special attention paid to Redtail. In particular, I will consider profitability of new wells currently being drilled. In view of a sizable part of CapEx likely being deferred to Q4 2017, I will contemplate the impact of Dakota Access pipeline.

Redtail wells fall short on production and display no record of improvement

Whiting has operated in Redtail for many years. When we examine the decline curves of company-operated wells of different vintages (well groups, segmented by the first year of production), we see consistency year after year. Ignoring the sub-par production of wells that came online in 2016 (on account of a limited number of wells), the output from wells that began producing in 2011, 2014, and 2015 looks remarkably alike. This is true for both oil and natural gas. The uninspiring results in Redtail stand in sharp contrast to the firm's performance in the Bakken, where steady improvements have been seen year after year.

Chart 1: Oil production from wells in Weld County, Colorado that began producing in or after the specified year, for 2011, 2014, 2015, and 2016.

Whiting Petroleum: Oil production from wells in Weld County, Colorado that began producing in or after the specified year, for 2011, 2014, 2015 and 2016
Source: Production data from WellDatabase and author's analysis

Weld County, Colorado contains both the Redtail field and the larger Wattenberg field. Noble Energy (NYSE:NBL) is a major operator in Weld County, with East Pony area being the nearest to Redtail among Noble's acreage. Noble has significantly more wells and provides a useful comparison point to help us judge the quality of Whiting's acreage and wells. Consider wells that came online in 2015 and later. Noble has about three times as many wells as Whiting, 330 compared to 95. Whiting's wells are less prolific by a wide margin. For example, the average cumulative oil production during the first 12 months amounted to only 71 MBbl for Whiting compared to 265 MBbl for Noble, according to WellDatabase. To be fair, Whiting's wells probably tend to be somewhat cheaper than Noble's at $4-4.5 million compared to $4.8-5.2 million. Still, Noble's nearly fourfold advantage in the quantity of oil produced points to inferior economics of Whiting's wells and is a potential explanation of Whiting's very low drilling activity in Redtail in 2016.

Chart 2: Whiting Petroleum vs. Noble Energy: oil production from wells in Weld Co., Colorado that began producing in 2015 or later.

Whiting Petroleum vs. Noble Energy: oil production from wells in Weld Co., Colorado that began producing in 2015 or later
Source: Production data from WellDatabase and author's analysis

Williston Basin: Whiting's continued improvements

I have previously covered Whiting's operations in North Dakota. In brief, newer wells have improved significantly over wells from earlier years in terms of output in the first 12 months. Past that point, the picture gets murky. For example, wells that came online in 2015 produced less oil than those from 2014, at the two-year mark. In turn, average monthly production from wells of 2014 vintage lags behind those of 2011, if we examine oil production 24 to 36 months from the moment wells started to flow.

Chart 3: Oil production from Whiting's Williston Basin wells that began producing in or after the specified year for 2011, 2014, 2015, and 2016.

Whiting Petroleum: Oil production from Williston basin wells that began producing in or after the specified year, for 2011, 2014, 2015 and 2016
Source: Production data from WellDatabase and author's analysis

Looking at natural gas, its gathering became better over the years, resulting in a solid trend of improving production volumes. Unlike oil showing increases for the first year of production at best, natural gas output of newer wells does not show signs of abating yet, with wells that came online in 2011, 2014, and 2015 showing steady progress year after year.

Chart 4: Natural gas (including NGLs) production from Whiting's Williston Basin wells that began producing in or after the specified year for 2011, 2014, 2015 and 2016.

Whiting Petroleum: natural gas, including NGLs, production from Williston basin wells that began producing in or after the specified year, for 2011, 2014, 2015 and 2016
Source: Production data from WellDatabase and author's analysis

DUCs or freshly drilled wells? The picture in Redtail differs much from the Bakken

Whiting intends, for the most part, to complete existing drilled uncompleted (DUC) wells in Redtail. As of February 2017, there were "105 Redtail DUCs". I estimate that only five new wells are to be drilled in 2017. Hence, most of Redtail CapEx will go towards completion of existing DUCs. At $3 million per DUC completion, 2017 will see significant savings in Redtail compared to drilling brand new wells at $4-4.5 million each.

In comparison, the company held 38 DUCs in the Bakken as of January 2017. This is a typical number of DUCs to have in inventory. The plan to have "55 Bakken wells to be put on production in H1 2017 and 68 wells in H2" means the firm will be doing a substantial amount of new drilling in the Bakken. Hence, it is the cost of $7.0-7.6 million of a newly drilled well that has to be considered in the Williston Basin, in contrast to the cost of DUCs being relevant in Redtail at least during this year.

Considering well economics

Certain assumptions have to be made to arrive at estimated ultimate recovery (EUR) figures, as well as the internal rate of return (IRR) and the net present value (PV10) of a well. I assume 8% terminal decline per year in the Bakken and 10% in Redtail. Reported gas volumes are split almost evenly between sold oil equivalent volumes of natural gas and natural gas liquids (NGL). NGLs are assumed to fetch 25% of realized oil prices. Natural gas is forecast to be sold at $1.15 per Mcf below the Henry Hub benchmark, taken to be $3.20 per Mcf. Completed well cost is assumed to be $3 million for a DUC and $4.25 million for a newly drilled well in Redtail and $7.3 million in the Bakken, using midpoints of price ranges indicated by the company. Royalty rate is taken to be 1/8; that is, the firm receives only 87.5% of revenue resulting from sales of the forecasted production of hydrocarbons. WTI is assumed flat at $55 unless stated otherwise.

The outsized CapEx allocation to Redtail is likely a one-time event

In the base case, oil is to be sold at $9 per barrel below WTI. A Redtail DUC has a 0.6% IRR and results in a loss of $0.6 million of present value due to IRR falling short of the assumed 10% annual discount rate. A newly drilled Redtail well has an IRR of -7% and is forecast to lose $1.9 million of PV10. In short, new drilling in Redtail is uneconomical. Absent a huge rise in oil prices, Whiting will likely suspend development in Redtail once the DUC inventory is exhausted by year-end.

Going back to economics of Redtail DUCs, the crucial variable affecting profitability is the differential, taken to be $9 above. Whiting falls short of Continental Resources (NYSE:CLR), a larger Bakken producer that has already managed to reduce it to $6.95 per barrel:

As expected, our oil differential has continued to improve with approximately 90% of our Bakken production now delivered to market via pipeline. The full company fourth quarter oil differential was $6.95 per barrel, while the full year was $7.33, both within guidance.

If Whiting could only manage to match Continental's Q4 2016 discount of $6.95 per barrel to WTI, a Redtail DUC would earn a 2.5% IRR.

According to Continental, "growing pipeline capacity should reduce basin differentials by at least $2". Oil realizations at $5 below WTI would raise Redtail DUC's IRR to 4.5%. In the most optimistic scenario seen by BTU Analytics for the impact of DAPL on crude differential in the DJ basin, likely applicable to Redtail as well due to geographic proximity, the differential tightening to $2.34 would only raise Redtail DUC's IRR to 7.5%.

It goes without saying that, even in the best imaginable scenario of the differential contracting to a quarter of the recent discount, the rate of return on a Redtail DUC is unsatisfactory. I believe that Whiting's exuberant view on EUR is a major contributor to the firm viewing Redtail wells as promising.

Whiting's EUR claims in Redtail are hard to reconcile with known production data

I estimate EUR of a Redtail well at 153 MBoe (the oil part being 110 MBbl), merely one-third of what is claimed in Whiting's March 2017 presentation:

  • Targeting 465 MBOE EUR for 960-acre spaced wells in 2017.
  • Targeting 655 MBOE EUR for 1,280-acre spaced wells in 2017.

Reconciling the discrepancy poses quite a conundrum. There is an interesting way to illustrate the relationship of EUR to known production, proposed by Enno Peters. The idea is to plot the average daily oil production in a given month against the cumulative production attained up to, and including, that month. This results in the chart shown below. A well is likely to be plugged before the output drops to 1 barrel of oil per day. The blue line joins the recent data points for wells that produced for around five years to the estimated oil EUR of 110 MBbl. The red line shows how the data points would have to line up in order to match the claimed EUR of at least 465 MBoe, meaning at least 300-350 MBbl of oil. Pointing somewhat closer, at around 250 MBbl, the red line appears to be inconsistent with known production data.

Chart 5: Daily vs. cumulative oil production of Whiting Petroleum's Redtail wells that began producing in recent years

Whiting Petroleum: daily vs. cumulative oil production of Redtail Niobrara wells that began producing in recent years
Source: Production data from WellDatabase and author's analysis

Increased CapEx in the Bakken may be justified

At $55 WTI, and in the base case of selling oil at $9 below WTI, a newly drilled Williston Basin well is estimated to earn a 15% IRR and has a $1 million PV10.

If Whiting managed to improve its oil discount to $6.95 enjoyed by Continental at Q4 2016, IRR would rise to 18% and PV10 to $1.5 million. BTU Analytics' forecast of Bakken differential shrinking to $4.39, if realized, would raise IRR to nearly 22% and PV10 to $2.1 million. In summary, Dakota Access Pipeline has the potential to improve economics of Williston basin wells by a wide margin.


Comparing economics of drilled and uncompleted wells in the Redtail field to those in the Williston Basin, I do not agree with Whiting Petroleum's claim that "Redtail DUC, in terms of returns and whatnot, is similar to a Bakken drill and complete". On the contrary, I see Redtail DUCs as inferior to newly drilled wells in the Bakken, and regard CapEx allocation to Redtail as potentially destroying shareholder value. Whiting's relatively greater optimism about Redtail EURs as compared to Bakken EURs is a likely explanation of the firm's view on Redtail. The company may be in a lose-lose position, the choices being completing Redtail wells that might never earn back the invested capital, or losing acreage and/or having to de-book proved reserves. The upside of Whiting's strategy of completing Redtail wells consists of being able to show production growth, at least until the firm exhausts its DUC inventory by year-end.

In contrast, Whiting's increased investment in the Bakken may be justified as long as oil prices do not go through another downturn. There is much room in improving Whiting's oil realizations. The rising tide brought about by Dakota Access Pipeline should lift all boats, even if Whiting fails to achieve the same discount to WTI as, for instance, Continental Resources.

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