Tag Archives: Hess Corp

Peaking in at Hess’ Production Results in the Bakken

I’m currently working on a Bakken operator efficiency article, but I’m not sure how long it’s going to take me and I’d like to keep this blog updated at least twice a week, so I thought I’d prepare a preview of sorts based on some of the research I’ve been doing.  This preview will focus on Hess’ (Hes) results in the Bakken where it has been using 16 rigs to develop its 800k net acres. Like any company with an acreage position this big, some of it’s good and some of it’s marginal.  The company is currently drilling to hold acreage so its production results have been inconsistent.

Why Hess? Well they’ve been producing in North Dakota since 1951, making them not only one of the state’s oldest producers but also one of its top producers with respect to volume.  To that end, it’s interesting to hear people who participate in wells with Hess speak of high AFEs and modest production volumes.  On paper, I would expect more from a company who has been drilling in the Bakken as long as Hess.

The company’s reason for lackluster production stems from its decision to hold all of its acreage, even the fringe pieces.  Production from the fringe pieces isn’t as good, resulting in weaker than expected production numbers.  In its Q4’11 earnings call, the company explained its higher AFEs are also a result of its HBP drilling program.  The company is preparing its drilling units for pad drilling, so the initial wells are bearing all of the infrastructure costs for the pad.  While this implies lower costs for wells down the road, it hurts the non-operators who are participating in its earlier wells.

A few notes on terminology: 1) An AFE is an “authorization for expenditure,” which is the bill an operator sends out to the non-operators/investors in a given well.  2) HBP=held-by-production.  Basically, Hess has to drill all of its leases before the initial term of approximately five years expires or they will revert back to the landowner and have to be leased again.

Below is production results and maps of the company’s various drilling areas in the Bakken. For those of you who aren’t familiar with North Dakota’s geography, below is a map of North Dakota by County which will provide you with perspective when looking at the maps further below.  The Bakken is found in the Western half of the state with the majority of production emanating from Williams, Mountrail, McKenzie and Dunn Counties.

Williams County Data source: North Dakota oil and Gas Commission.

The map above shows eight wells drilled in Williams County by Hess from 2010 to 2012.  The orange circles on the map indicate a township and the “pin” shows the section of the township where the well is located.  The wells are identified by name and IP rate (IP days varied due to limited data).  Hess’ best wells were in the Southeast portion of the county and production declined as the company moved Northwest.  The table below shows that Williams County is probably the gassiest Bakken County, with Hess’ wells averaging 80% oil.

Data source: North Dakota oil and Gas Commission.

Hess’ Williams County wells averaged 692 barrels of oil per day during the first 45 days of production.  This type of well performance implies a recovery of 77,887 barrels of oil during the first 239 days of production which will gross $6.6 million at $85.00 oil (if Hess sold all of its gas, which it didn’t, we could add on another half million).  Assuming the well grosses another 14,000 barrels during the balance of this year, it should have a payback period between two and three years assuming $10 million well cost and 80% NRI. The problem with Hess is some of these early Bakken wells are much more expensive (I’ve heard of some in the $17 million range), meaning you aren’t getting your money back anytime soon.

Mountrail County Data source: North Dakota oil and Gas Commission.

Hess’ acreage in Mountrail County seems to be solid, with the exception of the Shuhart well to the Northeast in 156-90.  That well is just North of some of the biggest wells in the Bakken, but it’s in an area where production begins to get a little spotty.  Also, the table below shows the company’s well performance is trending upwards, with its recent Johnson and Fretheim wells both having 30-Day IPs in the 1,000 barrels of oil equivalent per day (BOEPD) range.

Data source: North Dakota oil and Gas Commission.

While these numbers show Hess’ Mountrail County wells to be the company’s worst performer, its production in the county is trending up and the Shuhart well brings average production down.  The company has drilled a lot more wells in these counties to date (compared to the sample size), and it wasn’t my aim to show its worst performers, but the performance of the areas the company had leasehold in.  It should be noted that moving forward, the company will be drilling its best areas which will improve its production statistics.  The obvious takeaway here is that not all of the company’s 800k acre position is going to be economic.

McKenzie/Dunn County   Data source: North Dakota oil and Gas Commission.

While I didn’t look at every single Hess well to date, I can tell you the vast majority were in Williams and Mountrail Counties, meaning most of its acreage is probably in those two counties.  That’s unfortunate because the company’s best wells in my analysis (HA-Mogen and Arnegard State) were in McKenzie County.

Data source: North Dakota oil and Gas Commission.

As shown above, McKenzie and Dunn Counties (mainly McKenzie) are where the company has drilled its most economic wells to date.  Assuming $85 oil and an 80% NRI, payback period on these wells will average between one and two years.

Conclusion: Hess’ Bakken acreage lies in Williams, Mountrail, McKenzie and Dunn counties and tends to be in productive areas.  Where the company is getting itself into problems is with the high well cost of some of its wells.  Hess has apparently gotten this message, as it stated in its Q2’12 earnings call that it’s switching from a 38-stage hybrid frack (these wells averaged $13.4 million a pop during Q1’12) to a 34-stage sliding sleeve for its infill drilling or for all wells completed after the company’s acreage is HBP.

As for its decision to pile infrastructure costs onto the first well drilled on a pad, I don’t understand this decision and it would be interesting to know if other operators follow the same practice.  I’m not all that familiar with how pad drilling works and I’m a little skeptical of the company’s higher well costs.  Are we to believe that they’re really the result of infrastructure build out, or is there something more going on with the company’s Bakken efficiency?  I hope to answer this question with my full report which should be available next week.