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Crescent Energy Co
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Good day, and welcome to the Contango Oil & Gas Company Results for First Quarter 2018. Today’s conference is being recorded.
At this time, I would like to turn the conference over to Mr. Joseph Grady, Senior Vice President and CFO. Please go ahead, Sir.
Thank you. Good morning. I would like to welcome everybody to Contango's earnings call for the first quarter 2018. On the call with me today are Allan Keel, our President and CEO; Steve Mengle, Our Senior of VP of Operations and Engineering; and Tommy Atkins, our Senior VP of Exploration. I'll start off by giving a brief overview of financial results. Then Allan Keel will give you a brief overview of our current operations. And then we'll follow up with a Q&A. And just want to remind everybody that we take -- in our Q&A take questions from analysts that follow our stock closely. As we believe that is most constructive and productive use of everyone's time.
But before we begin, I want to remind everyone that our earnings press release and a related discussion this morning may contain forward-looking statements as defined by the Securities and Exchange Commission and which may include comments and assumptions concerning Contango's strategic plans, expectations and objectives for future operations. These statements are based on assumptions we believe to be appropriate under the circumstances. However, those statements are just estimates and not guarantees of future performance of results and therefore should be considered in that context.
And starting with the financial results, we reported net income of $900,000 for the quarter, or $0.04 per basic and diluted share comparable to that same amount reported for the first quarter of 2017. While the net income numbers were the same for each quarter, you probably notice in the release that there are number of non cash and profit loss items in each period that for the most part offset each other in comparing the periods.
Some of those are self explanatory and some I'll expand on a little more as we go along. Adjusted EBITDAX, a measure of operational cash flow as we define it in our release, was approximately $8.3 million compared to approximately $7.2 million generated in the prior year quarter, an improvement attributable primarily to slightly higher revenue. Cash flow per share exclusive of impact of changes in working capital was approximately $0.02 and $0.28 per share for the current quarter compared to $0.26 per share for the prior year.
Revenue for the quarter was $20.4 million compared to $19.4 million for the prior quarter, a slight increase attributable to higher oil prices and to a higher percentage of our production coming from oil and natural gas liquids. That is about 35% in the current quarter versus 28% of the total in the prior year quarter.
Production for the quarter was approximately 4.5Bcfe or 50 million cubic equivalents a day compared to 57.6 million for the prior year quarter, and at the lower end of our guidance for the quarter. Our guidance for the upcoming quarter is estimated at 41 to 46 million a day, the midpoint of which is about 13% below the first quarter due to two things. In mid May we weren't stalled the second plant stage of compression for Eugene Island field resulting in shutting of that field for an estimated two weeks. That field contributed approximately 60% of our total company production during the first quarter.
So the plant shut in makes up about two thirds of the quarter-to-quarter drop. Also contributing the lower quarter-to-quarter production is the fact that our Sidewinder and Gunner wells that we spud in the second quarter are being drilled sequentially from a single pad and then will be completed via zipper frac approach, with full production expected in July. So we will not be adding anything new production from drilling during the second quarter to help offset a normal decline. If timing works as we forecast which should bring two new wells on production during the third quarter, total operating expenses exclusive of production and ad valorem taxes were $6.1 million for the quarter, which is at the midpoint of our guidance and comparable to the prior year quarter despite seven additional wells in our West Texas field.
The midpoint of our second quarter guidance is comparable to the immediately preceding quarter. As noted in our release, we recognize a $9.4 million book gain on the sale of our Karnes Eagle Ford property for $21 million at the end of March. We also recognized $3.3 million in non-cash impairments and lease abandonment in the first quarter of 2018, most of which related to Vermilion 170 single well field. As required by accounting rules and the capitalized cost exceeds the estimated remaining future cash flows.
At the end of the quarter, we had approximately $79 million outstanding on our revolver, which has a $115 million borrowing base at the end of the first quarter. We are currently working with our bank group on a regularly scheduled borrowing base re-determination and should have that finished in the next few days. We expect to finalize that process shortly and do not expect any meaningful adverse result in that process. We expect that we will be able to find the remainder of our CapEx program for the year through internally generated cash flow, plan sales of additional amount non core onshore assets, and to the extent necessary temporary borrowings under our credit facility.
That concludes a financial review and now turns it over to Allan for an update on the operations.
Thanks Joe. We're happy to have everyone here with us today. As you could tail on Joe's voice, he's really excited about our progress that we're making with our drilling program and in the Delaware Basin. We've had quite a bit success over the last I'd say 12 months especially on the operations side. So it's really making progress there with the three -- excuse me we put five wells on production last year. We've already put three on production this year with two more on the pad that currently being prepared for a zipper frac starting in early June. We're currently in the process of changing drilling contracts and now expect our new rig to arrive this week.
We'll use that rig to commence drilling to Fighting Ace 2H which Wolfcamp B well. While we've continued to show improvement in our spud activity days, and this new more advanced rig should be a helpful and even greater reduction in reducing those days. A little bit over month ago we released the results of our first two Wolfcamp B wells, which was and has been new zone that we've tested across our acreage. So now we feel like we've proven up both the Wolfcamp A and the Wolfcamp B in our area. And so the next step would be to start drilling some Bone Springs wells which we're going to do that hopefully a little bit later this year.
Just for reference purposes, the River Rattler 1H, the first of two Wolfcamp B wells was our best day 30 day IP well a day. In early June, we will begin to zipper frac of the Sidewinder 1H, a Wolfcamp A well in the Gunner 3H, A Wolfcamp B well. These wells were drilled from the same pad and are located just south of the Rude Ram 1H and Gunner 2H wells. Our two best wells today that have been put on production for an extended period of time. Again as you saw in our release, we expect to have a rig going for the remainder of the year and will continue to test a combination both the Wolfcamp A, B and Bones Springs formations.
Our forecast is to drill another five or six wells got here in the Pecos County area after completion of the Sidewinder and Gunner wells. We'll also continue to look for prudent ways to increase the amount of development capital potentially drilling in late 2018 or 2019 should prices remains strong. We also continue to look for opportunities to expand our position in around our area. We think some of those may exist as a group with between us and our partner we control close to 14,000 acres now. And we started out with Karnes so we made some progress there. But we'll continue to look for either acreage acquisitions or producing property acquisitions in our focus area.
So with that that concludes our prepared remarks. And we'll open it up to the questions for you operator.
[Operator Instructions]
Thank you. And we'll take our first question from Neal Dingmann from SunTrust.
Good morning, guys. A nice late as well I know that well you described anything different that you all did on the completion side there, is it just trying to extend the laterals and push a little bit more on the proppant side.
Well, the big difference was it was our first B well. So we've been drilling on Wolfcamp A up until now and so a little bit deeper, like tries down so that was the fact that it's another rise was very encouraging force.
But in terms of the completion recipe and drilling wise now it's all pretty much the same thing.
Yes.
Good to hear, okay. And then just now can you talk a bit about you guys have had actually quite good luck on seems like bringing in the frac crews when you need them and all that can you talk about where you try to sort of frac some of these in groups kind of when you look at the remainder of the year, if you guys could talk about how you'll tackle that?
Well. We're certainly doing that with the Sidewinder and the Gunner well. We're doing a zipper frac on that one. That market is so fluctuating out there that sometimes you can't find anybody then sometimes you've got five guys calling it. So generally what we anticipate is that the market will get tighter, but don't think it's as tight as it has been in the past or as tight as it is today. So we've had some pretty good luck on getting frac crews.
Okay and then just lastly just I think you said two weeks just on the offshore downtime was that about two weeks?
Yes.
And we'll take our next question from Brad Heffern with RBC Capital.
Hey, good morning, everyone. I guess following up on Neal's question about the service side of things. Can you just talk about what the current leading edge well costs are?
Yes. I would say on the well that we just finished state what would you --
Right at around $10 million, $10.5 million.
Add or slightly below what we -- we have A and B wells, so very pleased with that.
Okay, that's good news. And then I guess on the takeaway front can you just talk through what sort of well head discounts you guys are seeing for oil and gas right now? And if we continue to see these double-digit Midland spreads is there any desire to defer completions and wait for better spreads or anything along those line?
Well just from a corporate standpoint. Brad, in the first quarter our average differential company-wide for oils right at WTI and just a tad under Henry Hub on gas like %. April it spread a little bit. Oil is still consistent with WTI; gas is a little higher at 6% off of Henry Hub. Well, obviously for West Texas we are subject to that mid push differential. It's blown out in the last few days for sure on average for April it was probably about a $1.25 for us, where it'll settle out still remains to be seen, but that's kind of where we are today.
Okay but no physical constraints in terms of getting the oil out or anything along those lines yet?
No.
Okay, great. And then I guess on zipper frac topic. Are you guys pursuing that just for efficiency reasons or do you see a need to sort of co develop the A and B?
All savings primarily you save -- you could save quite a bit anywhere well - just about a $0.5 million per well. So it's meaningful.
And we'll take our question Stephane Aka with Seaport Global.
Hey, guys, good morning. Just a quick one for me on the asset sales. You guys have been successful on that front recently. Can you just talk about whether you're currently working anything on the subject?
Well we're looking at it all of our non-core assets, Stephane. And with the idea of determining whether it makes sense to sell them in today's price environment versus the future value that they bring to us. When we started the year, we were sort of targeting a $30 million number. We, the first only sold for $21 million. We've got another $9 million to go to meet that goal. But we're trying to do it in an organized and prudent fashion and but we're looking at like I said every non core onshore asset for that purpose.
Understood, thanks for that. And then maybe last one for me just one for you Joe. Just kind of expectations on the re-determination anything you could kind of share there?
Well, again, we should have that finalized in the next few days but as of right now based on the conversations we've had along the way during this process, we don't anticipate a meaningful change or a change it would adversely impact our liquidity in a meaningful way.
We'll take our next from Ron Mills with Johnson Rice.
Hey, good morning. Hey, Joe just to follow up on the production-- the second quarter down sequentially. I think you said about half of it was may be related to the shut-ins Eugene Island. When we think about the timing of those shut ins in the second half production profile with two new wells coming in on in July. Any color or any thoughts in terms of what that production profile can look like and get back on track in the second half of the year?
Well, Ron, it's roughly about two-thirds of that drop looking at the midpoint of guidance comes from the shut-in of the Gulf of Mexico, the Eugene Island. We do have the two wells coming on, once the compressions on we expect to get some uplift from that compared to where we were before. So going forward, we would expect there be some increase in production. As you know, we don't give guidance beyond the current quarter because things like this can materially impact where we end up. So but if we expect certainly to increase from where we are today, but really can't give any guidance as to where that might be because of the impact.
I guess it would seem when you get kind of two thirds of that impact back from the Gulf of Mexico in and now that you're bringing a couple wells on at one time as opposed to one at a time that at least the ability to get back to kind of that first quarter run level seems pretty likely. Is that fair?
I would agree with that, yes.
Okay and you said you swapped out your rig and rig contractors. Can you just give a little bit more color on why -- who you're going to and who you're also using on your completions?
I'm sorry could you repeat that?
Yes what I was asking you talked about changing out rig contractors, just curious for a little color as to the thought process behind doing that. Who you're going to and also who you use for your completions?
Our completions, we've used a number of different companies. We've used COGS, we've used universal, and we've used C&J. C&J fixes the next two. As far as the rig is concerned, we just felt like we've had the rig we were using, and I'm not going to mention names here, I'm sorry, but for about a year, a little over a year now, we've had some few issues that just kind of at the wrong time. Something breaks or whatever and we just don't like it was a good opportunity rig came three that we felt like it was going to be an upgrade to the current rig and we went ahead and made that decision.
And is the upgrade -- is it a bigger rig, capable of drilling faster? Is it something that you think can be a benefit in terms of drilling efficiencies and potentially help with well cost? Or is it really more of --we wanted to potentially upgrade the project?
No. At the end of the day, we felt it's the rig we had was a substantial rig. But it is a top --the rig we're bringing is top class. It's got three pumps. It's got everything you need. The way that the rig moves is more efficient. We can -- and we think we can cut day or so off of our rig moves. We think that overall we ought to be able to increase or drop a day or hopefully two off of our drill time over the course of a well. And so that's perhaps two or three wells from start to finish for, it adds up over the course of the year. So gives us maybe another well in a 12 month period. So just do little there, lots of combinations -- lots of things that went into it. And but we again we grabbed it, came available, we grabbed it we thought that it was a first-class rig. And, again, I'm not going to put down the people that we had out there. But we felt like it was going to be an improvement or we wouldn't have done it.
And is that -- was the market -- are you starting to see cost inflation on both the rigs and the completions out there in terms of where your prior rig was? Where the new one is and how your upcoming fracs are being priced?
This is a little bit more on it on a day per day than the rig that we had, but we felt like that we can again make up for that easily on the improvement in the time that I just mentioned because there's a lot more than just the rig on a daily. You've got roll equipment et cetera. And so you can cut a day, you cut more than just a rig, just that one day of rig cost. On the completion side, at the moment the supply of fracers out there is I think in our favor. And so we've seen a drop in cost there as of late. We hope that continues but it's the market fluctuates quite a bit and but we're happy with where costs are today.
Great. Then one last one and Allan probably for you; you talked about the potential to kind of expand your 6,000 plus net acres via whether it's raw acres you are producing deals, curious in your area there around Baker's County can just give us a sense as to what that A and D market looks like in terms of supply near your existing footprint?
Yes. I think we have some operators that have large lease positions and this area around us is just-- you will recall the guys that came in and just swooped up all the acres from the private guys. And I think there's such a big inventory that a lot of these guys have that they may not ever get the point where they can execute. And some of their leases have provisions that where they have to drill sooner rather than later. And if they decide not to do that then there's clearly there's going to be opportunity. But if to get any value out of it all before just letting it expire. I think that they're going to have to --they're going to get active relatively soon because these areas where the leases will be coming up. So I think those are the primary factors driving that possibility.
That concludes today's question -and- answer session. At this time, I will turn the conference back to Mr. Allan Keel for any additional or closing remarks.
I just like to thank everyone for joining the call today. And look forward to giving you an update in the near future. Thanks for your interest.
This concludes today's call. Thank you for your participation. You may now disconnect.