Good day and welcome to today’s Contango Oil and Gas Results for the Fourth Quarter and Year-End 2016. Today’s conference is being recorded. At this time, it’s my pleasure to turn the conference over to Joe Grady, Chief Financial Officer. Please go ahead.

Thank you. I’d like to welcome you to Contango’s earnings call for the fourth quarter of 2016. On the call today are myself; Allan Keel, President and CEO; Steve Mengle, our Senior VP of Engineering; Tommy Atkins, Senior VP of Exploration; and Jim Metcalf, our Senior VP of Operations. I will give you a brief review of the financial results followed by Allan giving you a brief overview of our operations and then we’ll follow with the Q&A. And just as a reminder and as is typical for most companies. In Q&A we’ll limit questions to those from analysts that follow our stock as we believe that, that is the most constructive and productive use of everyone’s time. Before we begin, I want to remind everyone that the earnings release and the related discussion this morning may contain forward-looking statements as defined by 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, net loss for the quarter was 16.8 million or $0.69 per basic and diluted share compared to a net loss of approximately 111 million or 5.85 per share for the prior year quarter. As you noted in our release, if you eliminate all of the noise related to impairments caused by commodity price environment in the forfeited acquisition deposit 2015. Net loss before income taxes for the two quarters at 10.3 million for the current quarter compared to 11.5 million for the prior year quarter. Adjusted EBITDAX, a measure of operational cash flow as we define…

Thanks Joe and good morning everyone, thanks for being with us today. As Joe has just mentioned we've been spending much of our efforts this quarter on the development of our Southern Delaware Basin position and plan to continue that during the remainder of the year. As we've noted in some of our previous releases we were very pleased to found an opportunity to get into what's probably considered the hottest basin in the country right now and the way we were able to structure that deal last summer and we think that could be very impactful to our shareholders. We've split our first well during the fourth quarter last year, but that went on production late January and have three more in various stages of drilling or completion at this time. We've also exercised our rig option to drill our fifth well to be coming up soon. We anticipate having three more wells on production during the second quarter. All of these well included a 10,000 foot lateral with roughly 50 stages of frac, our fourth well, the Grim Reaper number one which we're drilling now will also include a pilot hole that we hope to get good information from potentially productive zones throughout the column. We will evaluate results along the way and continually review our strategic for the remainder of the year, but at this time it is to continue developing our acreage that we have which as Joe mentioned grows over 13,000 acres now. So we've been able to add to that position some as we've moved along since last summer. So very, very happy about that. You saw in our release that our 24-hour IP on that Lonestar Gunfighter well was just under 1,000 barrels equivalent per day, which we were very pleased with that…

Thank you. [Operator Instructions]. We’ll take our next question from Garth Grillo with SunTrust.

Good morning, guys. It’s actually Neil. Allan, a question on -- you’ve lined out now maybe perhaps up to the fifth-well. Can you talk about -- I know you hadn’t put out really any guidance beyond that, talk about permitting? If you would decide to keep that rig after that? Is that possible or just maybe can you talk about what -- I guess what's your alternatives or what your options after that fifth well?

No. We kind of continues option on that rig. So it’s our intent to keep it active throughout the year. We’re watching both commodity prices and service costs and results from our well. So far, so good, for the most part prices have come down a little bit in terms of the commodity price, service costs have certainly moved up given the demand for the area. So we’re encouraged by our results, we’re encourage our ability to add acreage in and around our position. But we always have to be cognoscente of what's going on this commodity market and also what the service side looks like as well.

And on that rig, you have the option -- are you just kind of paying well-by-well and you could talk about, I guess why I’m asking that, just about service costs both on the -- not just a rig side, but the completion side as well, what do you anticipate?

Yes. We do have an option, continuing option to keep the rig which we plan to do. And then in terms of service costs, we certainly have seen the increase as others have said spoken to kind of given what commodity prices are doing, it will be -- we'll be interested to watch along with others to see how that plays out overtime. But we have seen service cost increase kind of across all segments of the service sides. So I think it would be interesting to see what happens with tubulars, obviously, rig rates have gone up, proppant, all those things have moved up. So we're continuing to monitor that very closely as you can imagine.

Okay, and then just lastly M&A some suggest that there is a lot of thing about -- there is not as much out there, but again it seems like when I talked to you, you seem to still see a lot of things available. Could you just talk about M&A and are you looking -- if there is -- are you looking just particular in that Southern Delaware, where you're at would you look at entire term, maybe just anything you can add to that?

Yes, I think it's -- you try to -- one of the things that we are trying to focus on is been more focused from our geographic and geologic standpoint. So I think we are in terms of what we are doing here in the Southern Delaware, but the geology is not that different between Southern Delaware I mean the resilient characteristics may change as you move to the north or east or west or whatever, but the geology is fairly easily understandable. So anywhere there is a Delaware, would certainly be attractive to us. But as you know it's highly comparative, companies that are trading at such high multiples even after the correction that was made recently. I mean they still have somewhat of a competitive advantage when you are going after these larger packages. But yes, we think there is opportunity for us to increase our position, it may not be in 5,000 acres or 10,000 acre plots, but 500 acres is pretty meaningful for us. So we continue to look for those opportunities, but I would say that in terms of what we're focused on it would be more in the Delaware Basin region.

I'll look forward to all that activity. Thanks.

We will take our next question from Kyle Rhodes of RBC.

Just circling back to Allan's comments on additional acreage, you guys picked up the new 1,600 acres kind of since your initial entry into the Delaware, any details you can give on price you paid for that? Was it close to your initial entry price, I'm just kind of wondering what the current pricing is out there?

Yes, as you know Kyle it's very competitive, the price we're paying is not too dissimilar from what we paid in our acquisition back last summer. But certainly, given what's happened around us, what these larger packages have going for, 30,000 an acre or greater in some cases. It makes it difficult to try to add acres in big blocks because people obviously won’t get paid for that.

Got you, that makes sense. Then another question on Slide 9, I noted you guys are kind of drilling your laterals east to west and most energy wells appears to be kind of north to south, do you guys feel that lateral direction matters in this part of the Delaware? Any more color you can provide on your thoughts there?

I think Steve looked at that. Tommy looked at that in detail almost before we even got started. The early indications were that some of the east-west wells looked better, but at the end of the day they're all about, you can make a case for either way, and our acreage sets up perfectly to drill east-west lateral. So we couldn’t see any demonstrable evidence that one way was better than the other. And if anything, we would have said that east to west was a little bit better.

Got it. Okay and then can just let us know, how the Lonestar well cost kind of came in versus the expectations and then just kind of circling back to the service cost inflation team, remind us that kind of what's baked into the budget from -- and expectations of further cost inflation standpoint?

Yes, so originally last July when industry was dead, we were thinking these wells would be $8million to $8.5 million to drill and complete and hookup and so we -- as time went by and we started getting active and people become more active, so by the time December rolled around that $8.5 million well slid to really like $10.2 million, primarily driven by completion costs increase, not really as much as a rig or anything else. And that’s kind of the number we’re using in our budget. Even though, we’ve seen additional cost creeks and we anticipate that to continue, if prices -- the commodity prices stay in that $50 price range. If there is a lot of demand and the way people are just not that much supply when it comes to the fractures crews. So we anticipate there will some additional cost creek, but we’ll keeping our flexibility in terms of how much we’re committing to at any one-time. Relative to the first well, that was our first well, we had some mechanical issues with the first well, so we came in above our costs. But other next two wells, we were basically at the AFE number that we put out. So making progress at the fourth well we’re drilling a pilot hole, we’re going to do some additional testing and science on that. So it definitely may end up costing a little bit more than our AFE. But generally that’s what we’re seeing.

Got it and then just one more high level of strategic question if I could, if you guys are trading roughly add PDP, PV-10 value at the strip. What’s the strategy for getting more evaluation credit for your Permian acreage? Is it just simply executing and hitting your targets in terms of well costs and timing or is there anything else you guys are looking to do to kind of get more credit up there?

Yes. I mean you hit the nail on the head, we’re trading at a pretty significant discount to our PV-10 value and especially if you look at the five-year strip. We’re significantly discounted. So I mean we're getting in front of investors and trying to talk to them, and help them understand what we’re doing, what the economics of the play are. What our value company-wide looks like, cash flow from coming off our other assets, especially like the Gulf of Mexico. That's always a question as to, what’s your strategy, what’s your long-term strategy? Well, our strategy is to make money first and foremost, but in terms of how we get there. I think people would prefer for us to have single based focus, but we’ve got great cash flow from the Gulf of Mexico and we’re going to continue to use that cash flow to develop our assets. And right now Southern Delaware is a premier asset not only for us, but for most people that are active in West Texas. So that’s kind of our strategy is just to get in front of more investors and to tell them our story and really executing similar results.

Great guys. That’s it for me. I appreciate the color.

We’ll take our next question from Ron Mills at Johnson Rice.

Question on the well. You talked about the IP rate almost at 1,000 barrels a day still producing in the mid-800s. And you talked about the performance of that well versus the type curve that you had originally presented in your acquisition presentation and maybe some of the details of how you’re flowing it back to try to compare with the type curve data you would originally put out?

Yes. So in terms of Ron, are you asking how do we feel about that first well relative to our initial [Multiple Speakers]?

Exactly.

Well, I think it’s really early in the process. I mean if anything, it’s probably slightly below us, but we’re not really sure about that, because it’s just really early and we -- the way we flowed the well back, we had to control the flow back whereas a lot of our offset wells were just pretty much open choke from the very beginning. So we’re monitoring that and watching that pretty closely obviously. So hard to say, it’s early. Is all I can -- I would say right now.

I was just trying to get a sense of if part of that was the way you did the well back and if you knew how you were doing it versus what some of the offset wells were done, as part of that explanation.

Yes.

And then in terms of activity, it's sounds like versus January, the plan now is to keep that rig running, what do you think that means in terms of overall drilling plans for the year and what would you be looking for to potentially think about adding a second rig which was something that you had originally contemplated?

Well Ron, we originally had a pause in our budget, but based on the results for the first well and the fact we think it's important to keep our service providers on our team, we decided that will keep moving forward, because we're excited about what lies ahead for us. What will that mean to the budget, for the whole year obviously, CapEx will be up versus what we originally forecasted. But so what everything else hopefully. But we -- like Allan said we will continue to watch it all through the years. So to the extent that things -- the likelihood of a second rig is probably optimistic at this point, but you never know if results and/or prices are better than we expect, you might see one. But I think that would -- it will be optimistic to plug that into the model at this point.

Understood [Multiple Speakers]. But than from the -- from an overall well count standpoint, how many wells do you think you will get in now by not letting that rig go by for that kind of three or four months period?

Probably nine.

Nine more in addition to the first four?

No, nine in total for the year.

Okay.

For calendar year. So we'll end that with total 11 or 12 by the end of the year.

Okay. And then just from a financial standpoint, you talked about the liquidity under your revolver, is the plan is still really to try to maintain it as close to cash flows and if you have some near-term jobs that’s you just utilizing the revolver?

Well, that always our strategic, but we do have as we always say we do have -- or have said, we do have the capacity to go outside of that, if we think it's appropriate. And if we keep this going, this rig going for the whole year, we'd probably out spend some, but not a meaningful amount relative to our liquidity.

Then lastly, I think you -- just to go back to the acquisitions the incremental 1,600 acres, anything you spend on that acreage would be above and beyond the capital budget you had produced previously, correct?

We included some I mean our capital budget already. We added about $10 million in our original capital budget for acreage acquisitions in '17.

Okay. That’s all I have, thank you guys.

And at this time we have no further questions. So I would like turn the conference back over to your host for any additional or closing remarks.

Well that’s it. Thanks so much for everyone's participation and look forward to update you soon.