Current XEC Stock Info

We’re going to continue to push that envelope for as long as we’re in business – Tom Jorden

Cimarex Energy Co. (ticker: XEC) reported third quarter 2017 net income of $91.4 million, or $0.96 per share, compared to a net loss of $10.7 million, or ($0.12) per share, in the same period a year ago. Net cash provided by operating activities was $251.0 million in the third quarter of 2017 compared to $223.0 million in the same period a year ago.

Total company production for the quarter came in slightly above the high end of forecast, averaging 1,143 million cubic feet equivalent (MMcfe) per day (190.5 thousand barrels of oil equivalent (MBOEPD).  Oil production averaged 56,687 barrels per day, in line with the company’s estimate.

Cimarex invested $335 million in exploration and development (E&D) during the third quarter, of which $280 million is attributable to drilling and completion activities.  This brings year-to-date E&D expenditures to $937 million.  Third quarter investments were funded with cash flow from operations and cash on hand.  Total debt at September 30, 2017 consisted of $1.5 billion of long-term notes.  Cimarex had no borrowings under its revolving credit facility and a cash balance of $423 million.

Operations recap


Production from the Permian region averaged 628.2 MMcfe per day in the third quarter, a 21 percent increase from third quarter 2016. Oil volumes averaged 43,735 barrels per day and represented 42 percent of the region’s total equivalent production.

Cimarex completed 29 gross (16 net) wells in the Permian region during the third quarter.  There were 42 gross (16 net) wells waiting on completion at September 30.  Cimarex currently operates nine rigs in the Permian region.


During the third quarter, Cimarex completed 48 gross (14 net) wells in the Mid-Continent region.  At the end of the quarter, 89 gross (16 net) wells were waiting on completion.  Cimarex currently is operating five rigs in the region.

Cimarex is announcing drilling results from several Woodford shale wells in its Lone Rock area.  These wells were brought on production over the past several quarters and show some of the best returns the company has seen to date in the Woodford shale.  Cimarex has approximately 16,000 net acres in the Lone Rock area and has completed seven wells in 2017.

Also during the third quarter, Cimarex began producing from eight Woodford shale wells drilled as part of an increased density pilot.  The project tested both 16- and 20-well spacing per section.  Preliminary results show no significant difference in well performance between the two spacing tests, indicating that Woodford wells can be drilled closer together in future infill projects than they have been historically.

Source: Cimarex Energy Company

Q&A from XEC Q3 conference call

Q: Tom, you talked in the year very much about the capacity to generate free cash flow, while delivering strong growth. Could you speak to how you guys think about balancing shareholder preferences for overall more free cash flow generation?

President and CEO, Thomas E. Jorden: The conversation has been fascinating to us. And I think there are certainly different viewpoints, depending on which shareholders you speak with.

I think our long-term owners would like to see us invest our cash flow, make sure that we protect ourselves on a draconian downside. We’ve talked in the past, we stress test at $40 oil, $30 oil. We stress test at $2.50 flat gas and $2 flat gas. And these are all NYMEX prices. And as long as we can achieve outstanding returns and we have protection well above our cost of capital, at a draconian downside our bias is going to be to invest our cash flow.

Now we do pay a dividend. We cut our dividend last year, and we weren’t very happy about that. We did it as a matter of necessity in a declining cash flow environment. In February, we’ll reopen a discussion about dividend. And I think our bias was going to be to get that dividend back on a growth profile.

But we’re not actively looking at any share buyback program. We’re in the business to make good investments, as long as we’re getting the kind of historically outstanding returns that we are in this environment. That’s our business.

Q: You guys talked about conducting additional spacing pilots. As you think about trying to find the optimal design and development spacing and configuration, where are you going to be testing those limits? If there’s any specific area? Maybe it’s just across the board for next year?

Senior Vice President of Exploration, John Lambuth: I think in some ways it’s a testament that we’re getting very good at being able to understand the overall resource in place we’re trying to develop and understand what our frac design is doing. As I said, with the Clyde Copeland, the outcome we’re seeing from Clyde Copeland kind of fit what our preconceived model said it should do. It’s performing very well.

So in some ways I think we’re getting pretty good for each distinct interval of understanding the resource in place and what its full potential is.

Now still we’re going to push the boundary. I could argue right now the pilot I’d mentioned – the two pilots in Lea County, where we’re going to be testing much tighter spacing, both in the Avalon and in the Upper Wolfcamp in Lea County, that’s probably tighter than anybody else has done so far up there.

I feel confident we wouldn’t go out there with that design if we didn’t feel like we had a chance of achieving it. But there is some risk that maybe we do break it up there. But I think it’s also again, as I said, a testament that we’re just getting much better at understanding what we’re doing with these pilots. And how our frac is interacting or working in terms of the ultimate production we get.

Pushing the envelope

Thomas E. Jorden: There seems to be a bit of a nomenclature shift between the word pilot and the word development. As long as we’re drilling pad projects, multiple wells off each pad, it’s really development. And the fact that we’re testing some things and learning along the way is a side benefit.

We’re already achieving the capital efficiencies and the savings from multi-pad development. And by continuing to test spacing, continuing to optimize our frac design, we are extracting more value for each acre we own. And we’re going to continue to push that envelope for as long as we’re in business. I mean there’s – so if you’re looking for us to come up with a stamp that we can just replicate and put our curiosity aside, you’re talking to the wrong management team.

Q: Regarding the Mid-continent area, particularly the Meramec, at times it looks like the [Leota] Jacobs development is probably deferred at this point. What size program could the Meramec footprint handle at this point in time? Or what size do you think would be prudent, given what you know or what you don’t know about the rock?

XEC: I will tell you, we’re still working up our 2018 plans for Anadarko. And you’re right, we still need to work with Devon regarding the bigger long lateral development, although I think there’s strong sentiment that that Leota Jacobs will probably get pushed into late 2018, early 2019.

Right now we have quite a bit on our plate to still achieve in the Meramec. One of the big issues still is understanding what the ultimate spacing looks like in the Meramec. As we talked about a lot, there are a lot of pilots ongoing that we have an interest in, that we keep watching carefully. And then we our self are looking at several additional pilots that we’ll probably be funding next year to again better understand what our potential is in the Meramec. That’s kind of what our thought process is right now for the Meramec.

We’re certainly – of all the plays we have, and Tom kind of mentioned this, the Meramec is probably the the least one that we’re ready to go to any form of development, where we still have a lot of questions in both how many zones can we land in? How many wells per each zone? And even more importantly, what is the appropriate frac design? So those are some of the things that we’ll be trying to address in 2018 within the Meramec program.

Q: A question on Anadarko Basin, the Lone Rock project that’s really exciting. Just wondering, in addition to the Woodford, how is the Mississippian looking for that specific area?

John Lambuth: We are looking at that very carefully. In fact, we recently took a whole core through the Mississippian as well as the Woodford. We’re aware of some outside operated wells nearby that look rather interesting. And so we our self will be testing the – what we call the equivalent Mississippian or Meramec interval sometime and early 2018 as well, and then we’ll see what that potential is.

Q: Wanted to ask you about the Pagoda pad, looks like you’ve got quite a bit of data there now. Are you comfortable with that data to kind of declare victory and use that as your – I know you want to push the limits. But 16 wells per section in the Upper Wolfcamp Pagoda, is that going to be the standard or minimum for that area going forward?

John Lambuth: Yes, we’re very, very pleased with the Pagoda results. As you can see, we’re almost 180 days into it, and they’re holding up very well.

The only other comment I’d make though is that certainly that well design of 16 is very appropriate for the equivalent thickness or resource in place. So I can’t necessarily rubber stamp over all of our Wolfcamp acreage in Reeves County. But there’s a good part of it where 16 looks pretty good.

We are going to be testing even tighter coming up here soon. We’re going to add a third bench and go a little bit tighter still based on the Pagoda results. So as Tom said, we’re not going to rest on our laurels. We’re going to keep pushing that boundary in terms of how many wells can we get in to that very prolific Upper Wolfcamp section there in Reeves.

Q: And you mentioned, John, the results from the 10,000-foot laterals over in Culberson look pretty solid. Is 10,000 feet going to be the goal there now? And I understand it’s going to depend on acreage configuration. But also think you guys were talking about trying some laterals even longer than 10,000 feet. Is that something that’s still in the works?

John Lambuth: Yeah. Well, first comment is if the acreage allows us, then we are always a minimum at 10,000 feet in the Wolfcamp as well as any of our other intervals. That’s our going standard length of lateral.

That said, we do have a lateral, because the acreage allows us to do this, down south of Culberson. We have some acreage that we’re doing 2.5 miles on.

And, yes, there’s still a lot of debate about whether we should go even further. I know our drilling department is very anxious to talk about doing that.

And again it’s going to be a question of, will the acreage allow us to do that? There are places within the JDA. But we’ve talked about it. We’re right now, because of the way the sections line up, we’ve been doing 7,500 – opposing 7,500-foot laterals. There are still areas there where we could instead go 3 miles with that section.

So we are internally talking about it. Like I said right now the longest I’m aware of is we’re doing a 2.5-mile right now down south of the JDA.

Q: I know you don’t have a full 2018 plan out yet. But with these details and the success you’ve seen both in the Del now and in the Midland now with the down spacing, does this make you more inclined to do much more, I guess, batch drilling next year? Versus just maybe two or three? I’m just trying to get a sense of how large sort of the average development will be next year?

John Lambuth: Well, that is a very excellent question. It’s something that we our self are asking all the time in terms of what is the best capital efficiency from a development standpoint? Is it a half section? A full section? Three sections? What works best for us? And that’s something we’re spending a lot of effort on.

One thing I need to make clear, no matter whether it’s a half or full or whatever, all of them are from multi – are from multiple wells from a pad. There is a clear efficiency gain by putting a certain number of wells per pad.

Now we also struggle with, you may hit a point where you have too many wells on a pad. That’s something we’re looking at. But it’s fair to say just about everything we do now is in mind where you’re going to have multiple wells off of a single pad, regardless of whether it’s a half, full, or is multiple section development.

Thomas E. Jorden: This is a complex problem. In fact, John and I were discussing this earlier this morning, because there’s a – we get a lot of questions about, all right, when are you going to go into full development?

And that question suggests that full development is many, many wells manufacturing, let’s say 50, 60 wells in a project. And that sounds good from a top line, because you can have efficiencies, you can have cost savings, you can have infrastructure savings. But the capital required for a project like that and the time delay between first investment and first production is also a significant consideration.

It may be that there is some optimum that’s much smaller than that. I don’t know if it’s 8, 12 [wells]. I mean, we’ll figure it out as we go. But again we view this problem through a lens of fully burdened rate of return, and that that includes first investment to first production. It includes parent-child interference. It includes infrastructure investment required. It includes production bottlenecks. If you have too many wells flowing into a system, you have to overbuild it to accommodate peak production.

And so there’s a very, very complex set of criteria. We will view this problem in order to manage and maximize our full cycle rates of return. And so our engineers are hard at work on this. There’s some good creative thinking going on. I had some discussions with our Permian team on this this morning. They’re asking all the right questions. And I can’t tell you today whether our optimum answer will be dozens of wells per project or something a dozen or fewer. It may be different depending on the area.

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