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November 2014

Encana Presentation 11-13-2014

Posted by bernell on November 13, 2014

David Hill, Executive Vice President over Exploration and Business Development for Encana Corporation, made a 34 minute presentation at the Bank of America/Merrill Lynch 2014 Energy Conference today, November 13, 2014.

As it pertains to the Tuscaloosa Marine Shale, here is what I gathered from the presentation, from about the 29:00 minute mark to the end.

In response to an unintelligible off microphone question, Mr. Hill said:

“Yeah. The question is about the TMS and today’s commodity pricing. 

So, let’s pull back from the commodity pricing, first, and, you know, we approached the play this year and said, ‘Look, we need some time on the type curve.'  For us to deem it commercial, one of the biggest uncertainties was type curve performance.

So, you know, we could see some 24 hour IP’s and they looked promising.  There were some drilling challenges.

So, we really set about this year with two parts: one of them is to repeat the type curve across the acreage and the second part was to drill successfully. 

And, again, knowing that we’re just doing single well pads, we’re not going to get the RPH and multi-well efficiencies (Resource Play Hub essentially means the multiple well drilling pads).

But we wanted to see trajectories changing on the play from the drilling perspective. 

This is deep, this is hot and it’s high pressures. It’s a challenging drilling environment. The core pressure and the over burden and the in situ stress are closely aligned, so you can be over balanced, slightly over balanced and lose circulation.  You can be slightly under balanced and have well bore integrity issues.

So, you have to keep your eye on the ball when you're drilling.

To be honest with you, starting out the year we had some difficulties getting back to drilling and achieving our lateral length.

So, our lateral length is set for our type curve in the TMS at 7,100 feet and delivering anywhere from 600,000 to 800,000 BOE (Note…these numbers are total estimated ultimate recovery expressed in barrels of oil equivalent).

We had some trouble there (i. e., getting back to the 7,100 foot lateral).

So, we had to sit back and think about what was going on and so we worked on the mud program.  We created a whole earth model to help us manage the circulating densities and we lowered the target. 

So we went from the upper TMS to the lower TMS and that seems to have overcome our challenges.

The last 8 wells we’ve drilled in the TMS have met our 7,100 foot.  Our last three wells have IP’d 30 at over 1,100 barrels per day…this is of oil, not equivalent.

And, all the wells we’ve drilled this year…again I’ll use this word 'normalized.'  All the wells we’ve drilled this year have met our normalized type curve per thousand feet.

So, we’ve been pleased with that part of it.

So, now to get to the other part

So, it looks like the performance is coming around, now, and we need to work on the cost structure.

And, to be competitive in today’s environment in our portfolio we need to see some big efforts here on the cost structure.

But, we DID see improvement in our cost structure this year.  We’ve gone from about a $14.6 million AFE (Authority For Expenditure) and we’ve had a few of these..again, not changing lateral length, cause you can play games here and I can save $2 million by cutting off a 1,000 feet and tell you we’re doing good….but, what we did is actually dropped about a million dollars off of drilling costs and we see a line of sight here when we get to the RPH hub, doing multi-well pads, and we think we can lower these drilling costs further.

You know this has a great net back because we’re sitting at LLS, sitting on the market, but it also has a high supply cost, currently.

(Note: The LLS pricing means our high quality TMS oil brings a higher price than say oil in the Permian Basin and the fact that we're so close to the Baton Rouge refineries and existing oil pipelines helps reduce the transportation costs and improves the "net back" to the operating companies.)

So, in our portfolio it’s one of the plays that we really need to work on the cost structure to make it competitive.  And, that’s what we’re working on this year and be looking at our scenario analysis for 2015 we’re running right now is where does that play fit in Encana’s portfolio."

In response to a second unintelligible off microphone question:

(Note: I left out the first part of his response, since it was meaningless without knowing what the question was).

"…But, we definitely need to see things hit $12 million or lower at our 7,100 foot lateral.

The thing about that is if you’re doing $14 million wells at 7,100 foot, you’re at about $2 million per thousand foot and we need to see those come down to about $1.8 or $1.7 million."

The next question, in summary, asked whether all oil plays would cease drilling if the price continued to drop?

Mr. Hill provided, in general, the answer that he thought it would be decided on a play by play basis with the supply costs of each basin.  He also said things such as the strengths of the companies involved and how natural gas liquids pricing was affected would be a factor.


I thoroughly enjoyed Mr. Hill's presentation.  It provided as much or more "color" or explanation to what has gone on from the viewpoint of EnCana in the TMS in 2014 as anything I've seen. 

In summary, they have proved the play will produce the oil they thought it would produce.  On the production side of the equation, they are pleased.

But, the costs are too high.  They will be making some moves to lower costs going forward by using multi-well pads with zipper fracks, etc... I'm going to take a wild guess and say this will account for at least $1 million savings per well.   The remainder of the costs will have to come from infrastructure improvements in the play.

The Catch-22 is that I wonder how many companies will be planning to spend many millions of dollars to locate here if there is no commitment from the operating companies to stay? I certainly hope  enough will.

Finally, from Encana's perspective, assuming they determine the play can and will be profitable, the next thing to do is to decide just how profitable it can be in comparison to the other plays they are involved.

In other words, supposing they can make 20% return on their money at $80 oil, will this be enough? 

The answer easily could be, NO, if their other plays will return 20%+. 

Of course, they may consider what would happen should oil rise to $90 or $100 or even more in a few years.  Surely, they wouldn't want to have left a play they developed only to see another company reap the benefits of their investment?

I want Mississippi State to beat Alabama this week-end in the worst kind of way, but I'll swap that win for EnCana making the decision to aggressively develop the TMS going forward.

(Of course, I'd much rather State wins AND EnCana makes this decision.)

Stay Tuned!

What do you think about it?