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Good day, and welcome to the Contango Oil & Gas Company's Quarter Two Results 2018 Conference Call. Today's conference is being recorded.
At this time, I would like to turn the conference over to Mr. Joe Grady, Chief Financial Officer. Please go ahead, Sir.
Thanks, Claudia. Welcome everybody to Contango's earnings call for the second quarter 2018. On the call today are myself, Allan Keel, our President and CEO; Steve Mengle, our Senior Vice President of Operations and Engineering; and Tommy Atkins, our Senior Vice President of Exploration.
I'll give a brief overview of financial results. Then turn it over to Allan for a brief comment on our current operations. And then we'll open it up to Q&A and is typical, we'll limit that to analyst to follow our stock closely, as we believe that is most constructive and productive use of everyone's time.
Before we begin, I want to remind everyone that our earnings release and a related discussion this morning may contain forward-looking statements as defined by the Securities and Exchange Commission which may include comments and assumptions concerning Contango's strategic plans, expectations and objectives for future operations. Such statements are based on assumptions we believe to be appropriate under the circumstances. However, those statements are just estimates are not guarantees of future performance or results and therefore should be considered in that context.
Starting with the financial results. We reported a net loss of $7.2 million for the quarter, or $0.29 per basic and diluted share compared to a net loss of $6 million or $0.24 per basic and diluted share for the prior year quarter.
Pretax operating earnings, meaning revenue less expenses, but for other income expense improved from a loss of $6.3 million in the 2017 quarter, to a net loss of $4.1 million in the current quarter.
Unfortunately, that $2.2 million improvement in operating earnings was overshadowed by $2.6 million pretax loss on our outstanding derivatives during the quarter, compared to $1.5 million gain on 2017 quarter.
Adjusted EBITDAX, a measure of operational cash flow as we defined in our release was approximately $7.4 million compared to $10.2 million generated in the prior year quarter and that's a decrease attributable to lower revenue and lower production and realized losses on our commodity price hedges in the current quarter compared to realized gain in the prior year quarter.
Cash flow per share, exclusive of the impact of changes in working capital was approximately $0.25 per share for the quarter compared to $0.38 for the prior year quarter. Revenue was $18.4 million compared to $20.3 million in the prior year quarter, a decrease attributable to a decline in natural gas prices and lower production in the current quarter due to only one new well commencing production during the current quarter that couldn't offset regular field decline.
And two, our Eugene Island 10 field we shut in for two weeks during the quarter for a planned compression installation and maintenance. While we experienced a welcome to increase in crude oil and natural gas liquids prices during the quarter. It was not an to offset lower gas prices and lower production.
Revenue from crude oil however increased to $9.6 million for the quarter a little over 50% of our total compared to $6.5 million for the prior year quarter due to the increase in crude oil production from our Southern Delaware basin drilling program and higher crude prices.
Production for the production was approximately 3.9 Bcfe or 42.4 million cubic feet equivalent of natural gas per day compared to 58 million for the prior year quarter. And that was in our previously provided guidance.
This anticipated year-over-year decline in crude oil production was due to regular production decline as previously discussed shutting in our Eugene Island 10 field for two weeks for compression installation and the sale of some non-core producing properties. The Eugene Island 10 field contributed approximately 60% for a total company production during the first quarter. So, the plant is shutting in in the second quarter was meaningful.
Our guidance for the upcoming quarter is estimated a $43 million to $48 million equivalent per day as we begin production from our Sidewinder and Gunner wells and the restoration of full production rigs make Eugene Island 10.
Total operating expenses exclusive of production have loan taxes were $5.6 million for the quarter which was comparable to the prior year quarter and below our previously provided guidance. Our guidance for operating expenses for the third quarter exclusive the production has long taxes is consistent with the second quarter of between $5.2 million and $5.8 million.
Loss on derivatives for the three-months in 2018 was approximately $2.6 million as I mentioned. And of this amount, $800,000 of that for realized losses while the remaining $1.8 million was a non-cash unrealized mark-to-market charge.
Gain on derivatives for the prior year quarter was approximately $1.5 million with $400,000 realized and $1.1 million and mark-to-market gains.
That concludes the financial review. And now, I'll turn it over to Allan for an operations update.
Thanks, Joe, and thanks for everybody joining on the call today.
Our focus continues to be on developing our West Texas asset in the Southern Delaware basin. We continue to derisk that area. We placed one well in production in April this quarter and two more in July, bringing our total number of producing wells in the area to 10.
As continuing to release the Raging Bull 2H well, IP built over our type curve. The Gunner 3H also was similar to our type curve and the Sidewinder 1H well was below our type curve.
In total, we now have seven producers in the Wolfcamp A and two in Wolfcamp B. On the cost side of things, the cost to drill to complete both the Raging Bull 2H and the Gunner 3H came in just under $10 million per well.
So, we continue to chip away the rail costs and therefore enhance now our returns. We think we can continue to execute the drilling and completion that cost at that level are possibly somewhat below.
I think in the last quarter, we mentioned that we have changed our contractor with our rig, the first well we drilled with this new rig was recently finished at the five days, number 2H with rigs TD in 25 days, since it's been our best well to-date in terms of timing. That well to finalize [ph] is expected to begin completion operations in mid-August with initial flowback in September.
The rig is now - is not General Paxton 1H well, it was recently spud, as Wolfcamp A target and it's kind of look at in the South East section of our acreage position. We anticipate even drilling this well a little bit faster than the five days that we're happy with the rig and crew that we have now.
As we saw - as you saw in our release, after we finish this General Paxton well. We'll move back to Northern part of our acreage position is by the River Rattler number 4H and drill that and that's we're going to evaluate kind of in our next steps based of several factors including the outlook for netback pricing in the area.
The Midland-Cushing oil differential continues to decline and we'll have to take another look at that at what that means to our overall program and decide what the best strategy is for the company moving forward that we're in place with the results, for the north spud, we have been able to get our costs down and this continues to be activity around this that helps us further derisk our area.
So, with that, I will turn it back over to the operator for question period.
[Operator Instructions]. We'll take our first question from Neal Dingmann from SunTrust. Please go ahead. Your line is now open.
Good morning, gentlemen. Allan question, with your sort of plan going forward to finish up and complete the wells in process. You don't seem like you have been having any issues as far as you had just talking about sort of on the services side.
One, if you have been having problems on the completions obtaining and keeping those frac spreads. And then two, sort of on a go forward basis do you plan to sort of batch some of the wells as you have done kind of in the past or you know what's kind of the plan as far as completions going forward.
Well, with regard to just the execution of those the completions we have - we haven't had really any problems at all. Not anticipate any lower or any problems. So operationally we feel good about that. We sometimes - we'll vary some of the are [indiscernible] prop inner water, or some of those things that just more executional to achieve.
From a service standpoint, we've had really good availability to the completion market, I think that's been probably the biggest driver on our well cost coming of, I like to have, so we say a very beneficial aspect to that for us and so.
And then going to your question, Neal about kind of more of the pad drilling, we can certainly do that now that we have most of our leases are in pretty good spot, so we could do that. I guess the question for us is just kind of lag kind of between drilling and then completing if you wanted four well pad or whatever drilling the four wells and then having that lag time between first production. That would be the thing that we would have to determine, how that would work best for us.
Okay. And then just one follow-up on, I know most of your wells, I think have been again just in the Delaware have been Wolfcamp as with a few Bs.
Two questions here. One, Allan just if you could talk about between As and Bs, your thoughts about spacing there these days. And then secondly your thoughts about going up a little bit and starting maybe doing a couple of the second bound?
Yeah, we've tested a couple of different benches in the whole cafe, still evaluating that and I think it's still a little bit early for us there. But we are doing that. In terms of spacing of what we've seen from opposite operators is found as 60 spacing. So, we would anticipate that would work for us as in addition to that, so, that's how we got where we stand today don't know that any benches that will ultimately have inside that will get an interval. It could be as many as 3 but right now we've not focus much of our efforts on 2 zones there.
Very good. Thanks for the details.
Thanks, Neal.
We will take our next question from Ron Mills from Johnson Rice. Please go ahead. Your line is open.
Good morning, Allan. Question on the world results and in particularly to the Gunner and I guess the Raging Bull. Can you just give us an update now that you have more production issue on some of your older wells? How is your type curve changed? What are your expectations now from in terms of an IP 30? I think you said that couple of the wells were in line with your type curve and the third one was a little bit below. I'm just trying to re-rate the type curve and if there is any appreciable difference between your As and Bs?
I'll let Steve kind of respond to some of those questions regarding the type curve, Ron.
As far as the type curve, I, from the early perspective from the first 12 months of our type curve, we haven't really seen much change at all. I don't have, the type curve essentially has an IP of similar kind of in the 700 barrel a day of all range plus than gas and liquids. And so, we feel comfortable now with the first 12 months.
The real question is, what exactly is going to happen after 12 months, that's kind of where our data ends. We've looked at our nearest offset operator just adjacent to us to the North and their curve flattens quite a bit and that's our type curve considers that and really, so we get a little further out and in time,
I'm not sure that we're going to see much of change in type curve. So, for all practice purposes over the course of the last year and a half or so, the type curve really hasn't moved a lot. We just, we'll get more data we and I think we've got the first 12 months supported is kind of where we're at.
Steve just taken from the 700 barrels a day, was that oil or is that Boe?
Oil.
Okay. And the like when you think about the Gunner the 777, 773 that's Boe, correct?
Yes.
Okay, I am just trying to like I said recalibrate. Second, nice pick-up in the product mix in the second quarter as you brought some wells on. What should we expect in terms of product mix going forward. Allan or Joe as you add some more Delaware wells, but you also get the Gulf of Mexico back on online?
Well, Ron I would say the second quarter was a little bit higher than what you see going forward. Because we had to shut in the Gulf of Mexico for a couple of weeks, for the compression installation. So, I think we were around 40% or something like that. So, I would say that probably a little bit less than that for the third quarter.
Okay. And then last one for me. You talk in there, Allan about once you've finished showing these the next couple wells and bringing a couple of them online you're going to take a break. Is that something, is just to evaluate results and pricing, is that something you expect to kind of take off the rest of year and maybe resume activity in 2019 or what sort of a pause do you think you can hit here?
Well, I'm not certain that we will take a pause. We are evaluating that now. We have a combination of factors that would impact that decision. Our production level up, I have been on the other side of the coin, we've got these high differentials that pretty much take away all your PV right off the bat, due to that pricing.
So, several factors that we're evaluating right now as to whether or not what our plan will be kind of going forward, but we have a pretty big inventory of wells go drilled and this is our primary area right now. So, it'd be a very big decision for the company.
Is some of this limited in terms of liquidity, I know you have $15 million or $20 million it seems like available on your borrowing base but discussions with the bank particularly as it relates to your current ratio?
Well, Ron, we are actually evaluating a number of possibilities to that would position us to carry out our business plan specifically the drilling program at the current pace or even in more accelerated pace but also position us to potentially take advantage of opportunities to increase our footprint so that will impact what we ultimately do going into the fourth quarter especially and into the following year.
Okay, great. Thank you very much.
We'll take our final question from Mike Kelly from Seaport Global. Please go ahead your line is open.
Hey, guys. Good morning. Maybe just first should we talk about just how you guys feel the flow assurance book oil and gas going forward and just here in the turnabout the pipeline's almost full et cetera to see that what you're seeing kind on the physical side of things right now? Thanks.
Sorry, Mike that didn't come through very clearly. Could you ask that again?
Yeah apologize. Can you hear me, all right now?
Yes, much better.
Yes. Sorry about that. So, the question was really just kind of how your - I actually view the physical market right now on the Permian and we're hearing quite a bit about pipelines almost being full on both the oil and gas front just see what you're seeing from a kind of boots on the ground perspective and just give us the overall comfort level on the flow assurance front with those commodities? Thanks.
Okay. I'm sorry. So, yeah, right now we're not having any issues selling our well, obviously all the projection show that the market is getting very, very tight and later on and any reports into the third quarter maybe fourth quarter or even shows that there could be a problem there.
We've talked to our purchaser. We've got trucks and trucks become a problem. We're not putting [ph] on pipeline. We are trucking, but so far, they say that they've got us covered for the foreseeable future and that mean, we won't have a hiccup here in a couple of months. There is no guarantee of that, but right now we feel pretty comfortable that we're okay.
We're also getting to the point where we potentially can justify putting in a connection to a pipeline, oil pipeline on the Northern part of our acreage. So, our guys are working on and there is capacity there as well.
And so, our guys are working that analysis right now. And it's with the same pipeline that we're selling to today. So, we've got a relationship with them already.
And as far as AESCO, we've got two lines that go through our acreage and we're selling through both of those. And there is plenty of capacity on those for our current level of production.
All right, great. Appreciate that. And then as you evaluate whether to pull back potentially. Just curious how you - if differentials stay where they are in the future market is right. Will that - how you lean in this. Is that more sort of - in that environment would you pullback, or would you need to have sounds like some number of variables to play here and would you need to have potential JV partner coming in at that point to help how - just base case right now where you will be, if you don't mind. Thanks.
As you know we have a very good partner here already. So, in terms of capital, if we needed to be bringing an additional capital, there is a plenty of opportunity for that. But I think we have to look at the economics of the play. We have to look at our lease position mixture that we preserve that. And so that plus our liquidity all those things combined will be the drivers for kind of what direction we go forward.
As I mentioned earlier, we're looking at a number of different possibilities that will position us well to pursue whatever strategy we think is appropriate. And also, potentially take advantage of opportunities to increase our footprint.
Fair enough, guys. Thank you.
Thank you.
Thank you.
It appears that there are no further questions at this time. And so, I'd like to turn the call back to Mr. Allan Keel for any additional or closing remarks.
We just like to thank everybody to participate in the call today. And we look forward get everybody updated after our next quarter. Thank you so much.
Ladies and gentlemen, this concludes today's call. Thank you all for your participation. You may now disconnect.