MCF
#Thank you, and welcome, everyone, to our call today.
Joining me in the call is our management team that consists of Joe <UNK>, Steve <UNK> and Tommy Atkins.
Like to provide you with a brief overview, and then we'll turn it over to Joe for some financial information and we'll come back and talk about operationally what we're doing.
But before we get started, I want to remind everyone that we're ---+ that our earnings press release and the 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 are ---+ to be appropriate under the circumstances.
However, those statements are just estimates and not guarantees of future performance or results and therefore should be considered in that context.
Looking back on this past quarter, we've made a lot of progress with respect to our operations in the Southern Delaware Basin, Pecos County, Texas.
We seem to be really gaining some momentum there.
We had a really good quarter.
We've ---+ today now, we've drilled in the Southern Delaware Basin.
We drilled.
We have 6 wells that are producing, 1 that's flowing back currently, 1 that's going to be complete ---+ started its completion next week.
And then we're drilling a well now.
We've got the 1-rig program, as I think most of you are familiar with.
We did have a ---+ as in the release you saw this morning, we had 25% increase in year-end reserves, which was an increase of about 37.5 Bcfe.
We had about a 55% increase in SEC PV-10 value at year-end, 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, and 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 and our drilling operations in West Texas, and we look forward to having a very active year moving forward.
So with that, Joe, I'm going to turn it over to you and let you give a brief summary of our financial results for the quarter.
Okay.
Thanks, <UNK>.
First of all, Contango recorded a net loss in 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 it in our release, was 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 in a [nonmaturing] 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 Mmcfe equivalent per day compared to 64.3 Mmcfe per day for the prior-year quarter.
And that was just under the midpoint of guidance, caused primarily by some downtime related to the 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 a new production to commence from the River Rattler that just started flowback; and from the Ragin Bull #2, expected to start flowback in April ---+ in early April.
Total operating expenses, exclusive 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 $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 in 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 the 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 in activity based reduction in certain support functions in the corporate headquarters.
We had approximately $85 million outstanding on our revolving credit facility at year-end.
As noted in our current operations release, we currently forecast 2018 CapEx to be in the below $50 million range for a 1-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, but we expect to more than cover that shortfall with sales of noncore onshore assets.
And that concludes the financial review.
I'll now turn it back over to <UNK> for a more extensive operations update.
Thanks, Joe.
Yes, as Joe mentioned, we ---+ our focus continues to be derisking and the development of our Southern Delaware position that we acquired in the latter part of 2016.
In the release, in our operations release, it gives the specifics of our progress there.
As I mentioned earlier, counting the River Rattler that just started production, we now have 7 horizontal wells in production in Pecos County.
The first 6 producers were all in the Wolfcamp A, while the River Rattler's our 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 been ---+ encountered very few problems in our most recent wells, at getting them get into TD, which actually reduces the number of drilling days on each well that we drill.
And we ---+ as I had 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 a 1-rig program in place now.
We're going to continue to find ways to reduce our drilling and completion cost 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 well, the Ragin Bull #2, it being as good as our 2 previous best wells that 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 to the Wolfcamp B.
And we also will be testing the Bone Springs formation, which has been tested by some offset operators.
As Joe also said, we believe that our cash flow, combined with certain noncore 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 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.
Yes.
So, <UNK>, thanks for that question.
Yes, we do have plans to drill a well down here.
There's an operator down there that just drilled a Bone Springs test.
We're kind of watching that and awaiting the results from that well.
But yes, in the southeastern corner of our acreage, I think that's a General ---+ was it.
.
General Paxton unit that are ---+ a well that we would drill on our schedule later in the year.
Yes.
Steve, won't you.
Yes.
This is Steve <UNK>.
So on the Crusader well.
We ---+ first off is, we flow our wells up using annular gas lift.
We start out flowing up casing, and then we go to annular river 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 the annular gas lift does.
We think it's better, cheaper, et cetera, and that's why we do it.
And it's worked out pretty good so far.
We're actually producing more fluid than our offsets.
On the Crusader, however, what happens is, is as you've got ---+ you flow up casing, and then when the well dies, then you go in and you run tubing and you get prep work prepared for that.
And that can ---+ you can be shut-in for, sometimes a week or 10 days, depending on rig availability, et cetera, because they don't give 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 casing in the beginning and then lose that a week or 10 days, that we would go ahead and run tubing up front and do the annular gas lift from day 1.
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 sizes, et cetera, just all changes.
And so we're just kind of getting evened out on that.
I will say that it seems like the well is, has ---+ the decline is a little shallower than the rest of them, so that, maybe flowing lower rates helps.
We'll monitor that.
The next ---+ the second well that we did that on, that the same thing, where we ran tubing up front was our Ragin 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 plumbing these things out.
So.
.
Well, <UNK>, it is a slight outspend, but as I mentioned, we are looking at noncore 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 some.
We're obviously adding reserves as we go along, so hopefully, we'll not see any degradation in the borrowing base and maybe even an improvement as we go along the year as well.
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 in different plays struggle with keeping the wells online.
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 the number of workovers.
I mean, maybe you can get a year out of a submersible pump, but I'd say probably on average, it may be closer to 6 months.
And that's just a costly intervention.
So as far as would it cost for annular gas lift, you've got the compressor that supplies the gas.
We've got a central facility, so we're able to do that and get gas to all of our wells, basically, with 1 central compressor.
And when you have that rental and others than that, that's pretty much it.
So the operating costs are considerably lower than the SPs.
Yes.
So we have seen improvement in terms of our cost.
When we started here a little over a year ago, the service costs had ramped up pretty significantly.
But we are continuing to make progress in terms of our drilling days.
I think the ---+ one of the ---+ the biggest factor has been just the completion and the cost associated with that.
One of the things that we've been able to ---+ how we've been able to reduce cost is just adjust our completion recipe and also the amount of proppant that we're using, the amount of fluid that we're using.
We'll continue to see improvement in those areas.
So with the proppant 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 seen an improvement in cost from, I would say, something north of $11 million per well to something at $10.5 million or less.
So we're getting ---+ we're seeing some benefit of a little bit more experience and additional capacity added to the market out here.
Yes.
So I think that the drilling complete those wells out there.
You're probably looking at something in the kind of $3 million per well neighborhood.
The well that we participated in, the flowback on that was ---+ and the production from that well has been outstanding.
It is a somewhat of a statistical play.
We're drilling to carbonate reservoir that's ---+ 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 the well that we participated in, the rate of return on that well is going to be very, very high.
Well, I think it's ---+ go ahead, Joe.
I was just going to say, Brad, everything's for sale at the right price, right.
And other than the what we consider core, which is obviously West Texas, our source of cash flow is the offshore.
So other than those, everything has a potential.
But during the course of the year, we'll be evaluating each and every one, determine 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.
Just a couple of quick ones for me.
Appreciating the Q1 guidance that you put out, but was wondering maybe if you could speak to kind of the trajectory for the rest of the year on production.
And also just kind of how the mix should trend over time there.
Well, I would ---+ I think that our view is that ---+ we'll ---+ as we drill each well, it takes somewhere between, from the time we spud a well toward the time we bring a well online, is somewhere 75 to 90 days to get well on stream.
We'd like to reduce that time frame, but lining up these frac jobs is certainly a challenge.
But we're using that as our guideline.
We do have high-volume gas that we're producing from the Gulf.
And so when we're trying to replace that with a relatively low-volume oil.
So in terms of production guidance, I think we 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 our oil mix is certainly going to increase.
And to the extent we can reduce our time from spud to flowback, we will do that to try to enhance our production rates.
Okay.
That's helpful.
And then maybe just to kind of clarify.
So the $52 million CapEx number, is that inclusive of leasing and kind of other spend as well for the year.
Yes.
So the $52 million is---+ basically covers all of our activity in the Pecos County area.
We do have some minor leasehold cost in there.
We haven't really budgeted for participation in any drilling activity in the Georgetown play.
We're evaluating that play and working with the operator and other partners there to try to determine 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 trying to stay inside of cash flow.
But to the extent we go out, with these noncore asset sales, that will more than make up for any deficit there.
Got it.
Okay.
That's helpful.
And then maybe lastly for me.
Could you maybe quantify the weather impacts on Q4 volumes.
Probably, I'd guess in terms of quantity, I believe that it was probably, what, around 200 million cubic foot equivalent, plus or minus.
So what is that.
That's about (inaudible).
Well, we're still monitoring it.
I mean, obviously, when we cut back our ---+ I mean, we cut our proppant back to 2,500 pounds per foot to 2,250, and we cut our fluid back from 80 barrels per foot to 60.
And that's still consistent with what kind of the average is 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 concerned us a little bit, but we, again, believe that that was probably for different reasons.
But I can tell you on there, again, the Ragin Bull is as good as our best well, and we've been flowing the River Rattler back for a day or 2.
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.
We just appreciate everybody's participating in 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.
