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Crescent Energy Co
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Good day, and welcome to the Contango Oil & Gas Company Results for Fourth Quarter 2017. Today’s conference is being recorded.
At this time, I would like to turn the conference over to Allan Keel, CEO and President. Please go ahead, Sir.
Thank you and welcome, everyone, to our call today. Joining me in the call is our management team that consists of Joe Grady, Steve Mengle and Tommy Atkins. I'd like to provide you with a brief overview and then we'll turn it over to Joe for some financial information and then we'll come back and talk about operationally what we're doing?
But before we get started, 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 SEC 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.
Looking back on this past quarter, we made a lot of progress with respect to our operations in this Southern Delaware Basin, Pecos County, Texas. We seem to be really gaining some momentum there. We had a really good quarter.
Today now, we’ve drilled in the Southern Delaware basin. We drilled -- we have six wells that are producing, one that's flowing back. Currently one that's got to be completed -- started its completion next week and then we're drilling a well now.
We’ve got the One-Rig program and I think most of you are familiar with. We did have as in the release you saw this morning we had 25% increase in yearend reserves with shows an increase of about 37.5 Bcfe. We had about a 55% increase in SEC-PV 10 value at yearend, which is an increase of about $91 million.
We participated in a discovery in the Zavala, Dimmit County area for the -- in the Georgetown formation. We were not the operator of that well, but we do hold a fair amount of acreage in that area and kind of excited about that. We'll talk about that in a few moments.
But again, we've made a lot of progress operationally as well as reducing our cost in our drilling operations in West Texas and we look forward to having a very active year moving forward.
So, with that Joe, I am going to turn it over to you and let you give a brief summary of our financial results for the quarter.
Okay. Thanks Allan. First of all, Contango recorded a net loss for the quarter of approximately $5.6 million or $0.23 per basic and diluted share compared to a net loss of $16.8 million or $0.69 per share for the prior year quarter.
That improvement in our net results was attributable primarily to a few things. Lower cash G&A cost, lower DD&A and in the prior year a higher impairment number related to the impairment of noncore, undeveloped leasehold cost.
Adjusted EBITDAX, a measure of operational cash flow and as we define in our release there's approximately $10.2 million compared to $8.2 million generated in the prior year quarter. And that’s an improvement attributable primarily to the aforementioned reduction in cash G&A cost, better realized results from our hedging activity, and a gain on the sale of a small stock investment from a non-upstream company.
Cash flow per share exclusive of the impact of changes in working capital was approximately $0.36 per share for the quarter compared to $0.30 per share for the prior year quarter. Revenue was $20 million for the quarter compared to $21.7 million for the prior year quarter, a slight decrease attributable to lower production, offset in part by higher oil and liquids prices.
Production for the quarter was approximately 4.8 Bcfe or $51.8 million equivalent per day compared to $64.3 million per day for the prior year quarter. And that was just under the midpoint of guidance caused primarily by some downtime related to freezes in the month of December.
Our guidance for the upcoming quarter is estimated at $50 million to $55 million equivalents per day or roughly flat with the fourth quarter. Additionally, we expect new production to commence from the River Rattler that just started flow back and from the Ragin Bull number two expect start flow back in early April.
Total operating expenses inclusive of production and ad valorem taxes were $6.4 million for the quarter, which is at the low end of our guidance and equal to the third quarter, despite a fourth quarter accrual of approximately a $1 million from anticipated throughput deficiency for 2018 in one of our onshore properties.
Our first quarter guidance of $6.4 million to $6.9 million or is $6.4 million to $6.9 million and likely will be on the low end of that and that includes about $400,000 to $500,000 anticipated workovers.
Cash G&A expenses that is excluding stock compensation expense were $4 million for the quarter compared to $5.9 million prior year quarter due to lower performance bonuses accrued for 2017 and because of lower insurance and office cost.
Guidance for the first quarter of 2018 is slightly higher than the current quarter due to severance costs associated with an activity-based reduction in certain support functions in the corporate headquarters.
We had approximately $85 million outstanding on our revolving credit facility at yearend. As noted in our current operations release, we currently forecast 2018 CapEx to be in the low $50 million range for the One-Rig program for the year and roughly for 9 to 10 gross wells.
At that level that is currently forecasted to be a slight [outspend] [ph], but we expect to more than cover that shortfall with sales of non-core onshore assets.
And that concludes the financial review and now I will now turn it back over to Allan for more extensive operations update.
Thanks Joe. Yes, as Joe mentioned, our focus continues to be de-risking the development of our Southern Delaware acquisition that we acquired in the latter part of 2016. In the release in our operations release, we gave the specifics of our progress there.
As I mentioned earlier, counting the River Rattler that just started production, we now have seven horizontal wells in production in Pecos County. The first six producers are all in Wolfcamp A while the River Rattler is first Wolfcamp B well.
As we've mentioned previously, we did had experienced a number of challenges in our early wells and now we've made significant process to overcome all that. So very pleased with the progress that we've made and we've encountered very few problems in our most recent wells that are getting into TD which obviously reduces the number of drilling days on each well that we drill.
And as I mentioned earlier, we've also been successful in reducing our cost related to some of our completion work. That includes proppant liquids and chemicals. So, our view is that we'll keep our One-Rig program in place now. We're going to continue to find ways to reduce our drilling and completion costs without sacrificing our production performance.
We're very pleased with the team that we have in-house and also in the field that we can drill and complete these wells. We can design our production systems and especially with our last, our most recent we'll, the Raging Bull number 2, it's been as good as our two previous best wells. They cost a lot more. So, we're making really nice progress there.
As you saw in our operations release, we are going to be testing various zones in addition to Wolfcamp A. I mentioned the Wolfcamp B and we also will be testing at Bone Springs formation, which has been tested by some offset operators.
As Joe also said, we believe that our cash flow combined with certain non-core asset sales will be more than sufficient to fund our program. However, I would just add to that if we do see continued improvement in oil prices and we have successful drilling results, again with the success of our noncore asset sales, we might pursue other prudent ways of accessing additional drilling capital for an increase in activity later in the year. The details of each of the wells are in our release, but I'd be happy to discuss any of those.
So that really concludes our remarks at this point. And we’ll open it up to the operator for any questions.
Thank you. [Operator Instruction] And we'll take our first question from Neal Dingmann with SunTrust.
Good morning, guys. Allan, my first question was just on your operational plan for this year. When I look kind of at the position, do you anticipate drilling much down in that let's call the South East Port -- the most Southeast portion down in Pecos.
So, I'm just wondering if you could talk about how you plan to sort of hit your activity this year, regionally speaking?
Yes. So, Neal, thanks for that question. Yes, we do have plans to drill a well down there. There's an operator down there that just drill the Bone Springs test. We're kind of watching that and awaiting the results from that well.
But in the Southeastern corner of our acreage, I think that's a general, was General Paxton unit, well that we would drill on our schedule later in the year.
Okay. And then, [indiscernible] it was a little bit less than some of the previous wells you'd had, is there anything different there or was it just more [indiscernible] impact on it?
I will let Steve why don’t you.
Yes, this is Steve Mengle. So, on the Crusader well, first off is we flow our wells using an annular gas lift. We start out flowing up casing and then we go to annular gas lift that gives us the maximum rate. We're trying to find a solution that we can move as much rate as possible without having to go to submersible pumps and annular gas lift. We think it's better, cheaper, etcetera and that's what we do it and it's worked out pretty good so far. We're actually producing more fluid than our offsets.
On the crusader and however what happens is that you've got, you flow up casing and then when the well dies, then you go in and you run tube and then get prepared for that and that can -- you can be shut in for sometimes a week or 10 days dependent on rig availability etcetera, because they don't give you any warning, when they die, they just die.
So, on the Crusader, the Crusader was the first well that we decided that rather than flow up the casing in the beginning and then lose that week or 10 days that we would go ahead and run tubing up front and do the annular gas lift from day one. And so, I'm not saying that's the only reason, but that is something that we did different on that well.
Just the whole relationship between flow and choke sites etcetera just all changes. So, we are just kind of getting evened out on that. I won't say that it seems like the well has declined, there is a little shallower than the rest of them. So that maybe blowing lower rates helps I don't know, we'll monitor that.
The next, the second well that we did that on the same thing where we ran tubing upfront was a Raging Bull 3 and that looks to be consistent with our best wells. So, we're just -- we're understanding how to flow given the way that we're performing these things so.
Okay. Thanks for the details. Allan, one last question for you or Joe, just on liquidity, you don't have much of an outspend this year, but you're getting a little bit tied on as far as what's left on the credit facility.
So maybe if you could just talk a little bit about thoughts are you looking at noncore sales or as you approach the end of the year with that One-Rig program, what's your thoughts about the liquidity?
Well, Neal it is a slight outspend. But as I mentioned, we are looking at non-core asset sales. We've already started the process on some and we feel good about those being able to cover whatever shortfall we end up with plus, we're obviously adding reserves as we go along.
So hopefully, we will not see any degradation in the borrowing base and maybe an improvement as we go along here as well.
Very good. Thanks, so much guys.
Thanks Neal.
And we'll take our next question from Brad Heffern with RBC Capital.
Hey, good morning, everyone.
Hey Brian.
On the running tubing and gasless before flowback, can you just talk about what the cost savings is from that?
I'm not sure I can give you exact numbers, but -- the reason we wanted to avoid the submersible pump is everything that we've seen, different operators and different plays struggle with keeping the wells on line, they're not -- they don't handle sand production whereas we can handle sand production with gas lift.
And so that can cause problems with the pumps and we have seen -- we have seen the number of workovers, maybe you can get a year out of a submersible pump, but I'd say probably on average it may be closer to six months and that's just a costly intervention.
So as far when it cost for annular gas lift you know you've got the compressor to supply the gas, we've got a central facility, so we're able to do that and [get gas] at all other wells basically with one central compressor and we have that rental and other than that that's pretty much it. So, the operating cost are considerably lower than the ESPs.
Okay. That gives me a good idea. Thanks for that. And then can you just talk about what the leading edge well costs are for you guys right now and how you are thinking about service costs in 2018? Are they -- do you have a lot of them locked in at this point?
Yeah so, we have seen improvement in terms of our cost. When we started here a little bit over a year ago, the service calls it ramped up pretty significantly. But we are continuing make progress in terms of our drilling days. I think the biggest factor has been the just the completion and the cost associated with that.
One of the things that that we've been able to help reduce costs is, just adjust our completion recipe and also of the amount of profit that we're using, the amount of fluid that we're using. We'll continue to see improvement in those areas.
So, with the proper market kind of evolving out there especially with these West Texas mines opening, that's going to continue to be something that we're going to follow very closely.
But we have we have seen an improvement in cost from I would say, something north of $11 million per well to something at 10.5 or less so. We're seeing some benefit of that more experience and additional capacity added to the market out here.
Okay. Got it. And then on the Georgetown Play, can you talk a little bit about what you guys think the economics look like there. Obviously, there are open hole completions, I imagine the declines are pretty substantial but at the same time they are cheap wells as well?
Yeah. So, I think that to drill and complete those wells out there, you're probably looking at something in the $3 million per well neighborhood. The well that we participated in, the other flow back on that was and the production from that well has been outstanding. It is a somewhat of a statistical play.
We are drilling to carbonate reservoir the key out there is being connected to the fracture system. So, there is some science involved, but it also involves a little bit of statistics in terms of what your results are going to be.
But I would tell you that well we participated in the rate of return on our wells going to be very, very high.
Okay. And then just one more you've talked about not asset sales a couple of times. Can you talk about what the non-core assets are, is that anything other than the Permian or how do you think about that?
Well I think - it's go ahead Joe.
Just going to say Brad, everything's for sale at the right price right. And earlier than the -- what we consider core which is obviously West Texas are source of cash flows offshore. So other than those, everything has the potential.
But you know during the course of the year will be evaluating each and every one term and what the value is to keeping it versus what we can sell for. So, but again from a total standpoint what we expect from that exercise will more than compensate for the outspend that we have in the initial budget.
All right. Thanks Allan.
And we'll take our next question from Stephane Aka with Seaport Global.
Hey guys, good morning.
Good morning.
Just a couple quick ones for me, appreciating the Q1 guidance that you put out, but I was wondering if you could speak to kind of the trajectory for the rest of the year on production. And also, just how the mix should shift trend overtime there?
Well, I would I think that our view is that, as we drill it well it takes somewhere between the time we spot a well to the time we bring the well on line, it is somewhere 75 to 90 days to get a well on-stream. We'd like to reduce that timeframe but outline of these frac jobs is certainly a challenge.
But we’re using that as our guideline, we do have the high-volume gas that we’re producing from the Gulf. And so, we're trying to replace that with relatively low volume oil. So, in terms of production guidance, I think we’d provide that on a quarterly basis.
Joe, I don’t know if you have any further comments regarding any kind of view on guidance for production, but all mixers only going to increase. And to the extent we can reduce our time from spud to flow-back, we will do that to try to enhance our production rates.
Okay. Okay. That's helpful. And then maybe just to kind of clarify. So, the $52 million CapEx number is that inclusive of we seeing and kind of other spend as well for the year.
So, the $52 million is, basically covers all of our activity in the Pecos County area, we do have some mild leasehold cost in there. We haven't really budgeted for our participation in any drilling activity in the Georgetown play, we’re evaluating that play and working with the operator and or the partners there to try to determine the kind of the path forward there.
But again, those wells are relatively inexpensive. And we've got - we don't have a large working interest there. So, any incremental capital required to develop that is not going to be all that impactful.
And as Joe mentioned earlier, from a liquidity standpoint given the fact that we're right at you know trying to stay inside of cash flow, but to the extent we go out with his non-core asset sales that will more than make up for any deficit there.
Got it. Okay. That's helpful. And then lastly for me, could you maybe quantify the weather impacts on Q4 volumes?
Probably, I guess in terms of quantity I believe that, it was probably was probably around 200 million cubic foot equivalent plus or minus so what is that. That's…
Okay. Okay, got it. That's it for me guys. Appreciate it.
Thank you.
And we'll take our next question from Ron Mills with Johnson Rice.
Hey guys, this is [Don Mackintosh] on Ron. I was wondering if we could go back a little bit to the changing compression style here run the tubing ahead of flowback and then also you reduce profit concentration?
And how you're thinking about that moving forward? Are you still in a testing phase or is this kind of what we're going to go with throughout '18?
Well we're still monitoring it, obviously when we cut back our -- we cut our profit back in 2500 to 2250 and we cut our fluid back from 80 barrels per foot to 60 and that's still consistent with what was kind of the averages of that people are doing in the play. So, it's not -- we didn't change it too dramatically.
But we are obviously monitoring results just to be sure that we’re not hurting our overall flow. The Crusader concerns us a little bit, but we again believe that, that was probably for different reasons. But I can tell you on the - again the Raging Bull is as good as our best well. And we've been flowing River Rattler back for a day or two.
And in terms of the fluid that we're seeing out of it, I mean again because it gets back to total rate that we can flow out of these things. And the River Rattler so far is in line with our better wells as well. So that’s kind of what we're looking at.
If we end up making overall less total fluid then we’ll reconsider, but we haven't seen that yet.
Thanks. Thank you. Got almost everything. Appreciate it.
Thank you.
It appears there are no further questions at this time. Mr. Keel, I would like to turn the conference back to you for any additional or closing remarks.
We appreciate everybody participating the call today. And look forward to updating you in the future with the results of our activity for the next quarter. So, thanks again for joining us today.
And that concludes today’s conference. Thank you for your participation. Now may now disconnect.