Allan Keel - President and Chief Executive Officer Joseph Grady - Chief Financial Officer Stephen Mengle - Senior Vice President of Engineering Tommy Atkins - Senior Vice President of Exploration James Metcalf - Senior Vice President of Operations.

Neal Dingmann - SunTrust Robinson Humphrey Ronald Mills - Johnson Rice & Co. LLC Kyle Rhodes - RBC Capital Markes.

Good day and welcome to the Contango Results for First Quarter 2017. Today’s conference is being recorded. At this time, I would like to turn the conference over to Joe Grady, Chief Financial Officer. Please go ahead sir..

Thank you Erica. And I want to welcome everybody to our call this morning. On the call are myself; Allan Keel, President and CEO; Steve Mengle, our Senior Vice President of Engineering; Tommy Atkins, Senior VP of Exploration; and Jim Metcalf, our Senior VP of Operations. I will give you a brief overview of the financial results.

Allan will give you a brief overview of current operations and then we will open it up to Q&A, where we will entertain question from analysts that follow our stock as we have done in the past, as we believe 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 a brief summary of the financial results for the quarter, we have recorded a net income for the quarter of approximately $900,000 or $0.04 per share compared to a net loss of $11.4 million or $0.60 per share for the prior year quarter.

On our pre-tax basis our net income before taxes was $1.1 million for the current quarter compared to net loss before taxes of $11.3 from the prior year quarter. As noted in our release, the current quarter included $2.9 million in pre-tax gain on the sale of a non-core South Texas gas assets.

Exclusive of that gain, our pre-tax net loss would have been approximately $1.9 million an improvement over the prior year attributable to higher revenues, lower operating cost, lower DD&A and impairment and improved results from our equity investment in Exaro Energy.

Adjusted EBITDAX, a measure of operational cash flow as we defined it in our release was approximately $7.2 million nearly flat with the prior year quarter. As the improved cash operating results, I just mentioned were offset in large part by lower realized benefits from our hedges in 2017 compared to 2016.

Cash flow per share was approximately $0.26 per share for the quarter. Revenues for the quarter was $19.4 million, an increase over the prior year quarter as prices were up dramatically compared to that prior year period. Our average equivalent price for the quarter was $3.75 per mcfe compared to $2.43 per mcfe last year.

Production for the first quarter was 5.2 bcfe or 57.6 million equivalents per day which was on the low end of guidance due to some minor maintenance related shut-ins on certain offshore wells for safety reasons, and a slight delay in bringing our new West Texas production from our drilling program.

As we discussed on our last call, in giving that guidance production for the first quarter of 2017 also reflected the loss with an estimated 1.4 million per day for the quarter on average due to due to compressor failure at Eugene Island 11, and that for 26 days and the compressor has since then replaced and productions has been restored to complete failure rates.

The decline compared to the prior quarter was as expected due to our suspension of drilling for the last year and half in response to low and uncertain commodity price environment.

The midpoint on our guidance for the second quarter of 2017 and is comparable to the first quarter, as we started to reflect new productions from our drilling program in the Southern Delaware Basin.

Total operating expenses exclusive of production and [indiscernible] taxes were $6.2 million for the quarter, better than guidance and below last year's $6.7 million as we continue to find ways to reduce costs and operate more efficiently.

Guidance was approximately $6.2 million to $6.8 million for the second quarter of 2017 is slightly higher than the first quarter than that due to anticipated work overs in our South-East Taxes area, due to a commencement of production at the Southern Delaware Basin.

On the CapEx, we continued our Delaware Basin drilling program that we started in late 2016 and had commenced production on our first three wells. We previously announced results on our first well and we will be prepared to release results on the second and third well our 30 days rate by the end of May or early June.

As noted in our previous release, we currently anticipate focusing on the Pecos County area for all of 2017.

Our current CapEx forecast for the year is to be between $50 million and $55 million approximately $40 million to $45 million which is to drill and complete an estimated eight wells in that area and up to $9 million for [Contango] (Ph) tack on leasehold acquisitions.

We expect that the vast majority of the drilling CapEx will be funded with internally generated cash flow. We currently have $59.7 million outstanding on our credit facility and our borrowing base was just re-determined and through November 2017 at a $125 million.

So we also posses the capacity to accelerate drilling in the Delaware basin if we deem appropriate later in the year. That concludes the financial review and I’ll now turn it over to Allan for an operations update..

Thanks Joe and thanks everybody for joining the call today. As Joe just mentioned, we do have good liquidity and we also have pretty good leverage metrics compared to our peers. We feel pretty good and fortunate to be in that position, we managed through the down turn clearly well.

So we are excited about implementing our operational plan as Joe said in the Southern Delaware basin over Pecos County. We have had a rig active there since late last year, we have got three wells on production now, we will have the results from the last two wells in later May or early June. Just for your information.

We drilled our fourth well called the Grim Reaper 1H, that well was originally designed to be a pilot well through the lower Wolfcamp and then we drilled a later into the upper Wolfcamp, where we had part of casing in that well and we were forced to complete that as a vertical well.

So we [indiscernible] three different sections of the lower Wolfcamp and we are in the process of testing those zones individually. After we finish drilling the Grim Reaper as a vertical well, we moved the rig over to the northeast and are now currently drilling what we call the gunner location.

As with the previous wells the horizontal wells, all these wells include an approximately 10,000 foot lateral with around 50 stages of frac. We have exercised our rig option following the gunner well for location that will likely be a well back to the southwest of where we are currently located.

Our technical team continued to look at different ideas and tweaks to our completion recipe with respect to [indiscernible] fluids, spacing cluster, et cetera to determine the most productive and cost efficient completion strategy. On the Lonestar-Gunfighter, our production is hanging in there, we are pleased to what we have seen so far.

I would say the past five day or so that well is going to average around 590 barrels equivalent per day and that’s again about 70% plus oil and we are in the process of rowing tubing on our two wells the Ripper State and the Rude Ram that’s wells two and three.

We have those production stats to released to everyone like I said in the later May or early June. We expect this to have the same type of results that we saw on the Gunfighter with a similar ore cut and we are going to continue to develop our acreage here and derisk it.

We think that its consistent with all the acreage around us in terms of other operators and so therefore we are pretty excited about what the prospects are for us to continue to develop this acreage and hopefully at some point see some reorganization of that value in our share price.

So we have no other areas that were currently drilling in, but this is our complete focus and we continue to be so as we move forward through the year. So with that, let’s open it up for questions..

[Operator Instructions] And will go first to the line of Neal Dingmann from SunTrust. Please go ahead..

Good morning, guys. And a question for you and Joe, you mentioned that the press release going back to the Grim Reaper likely after completion of this current well. Just your thought on a little bit longer term, you guys have been very cautious and it has paid off as far as just on the strategy.

So again, if I would look at say 45 versus 55 oil environment.

How might things change, what you finish up with that Grim Reaper, how you look at things maybe broader after that?.

Well I think at this stage we are continuing to keep the one rig working at $45 to $50 price range, we don’t see the real benefit of adding a second rig, because our strategy is to get our acreage all the [indiscernible] and we can do that with a one rig program.

We don’t think that with prices in that range it really justifies us to increased activity. Yes..

Makes sense and then just secondly, talked about maybe just as far as with completion activity, how far is in advance having line things up and challenge or just how that's going right now?.

Yes, we have been very fortunate with been able to have access to completion capacity that we needed. I would to say on average we probably had - after we finished drilling the well, I would say 30 days or less before we could get a completion drill out there.

So it's as we have talked in the past I mean that seems like that would be more challenging as we move forward, but thus far we have got great working relationship with the people we use and they have been very loyal in terms of providing their services to us..

Very good thanks guys. Great activity..

[Operator Instructions] will go next to the line of Ron Mills with Johnson Rice. Please go ahead..

Good morning Allan.

You mentioned your technical team is staring to continue to look at well design and completion design changes, given the 10,000 foot laterals and that it sounds like you have settled pretty much on 200 foot spacing, but what are some of the other changes that they are contemplating and how are your profits levels or use of [Indiscernible] comparing to what something your offsite operators are doing?.

Hi this is Jim Metcalf. We try to change a minimum of things between the Lonestar Gunfighter and the second and third completion on the Rude Ram and Ripper State. So we have stayed with the propane concentrations in the fluid volumes and what we did change was the concentrations of the different sand sizes.

We want from basically a 50/50, 100 mesh 40/70 to more of a 20% or 25% 100 mesh 70% to 75% and 40/70.

We were experimenting with fewer clusters within the 200 foot space facing and we have also added in the last two wells the complex nano-fluids and we are hoping to see some positive results obviously from that and before we decide what changes will continue to add on the subsequent completions.

Most likely the next step would be to shorten our space facing and we will take it slow not changing too much between each completion, so we can have confidence that we understand why we get the results we do get..

Okay, and then on the production profile of the Lonestar Gunfighter well, now that it's been online since January, I think on the last call we had talked about potentially having a little bit flatter profile.

How has the production profile of this well been since the IP rate and in terms of relative performance versus your type curve?.

This is Steve Mengle, so on the production profile, I mean we are 90 days into it, so I mean we still have a lot to learn, but I would say in general when we are flowing at [Casey] (Ph) which we have into the last 90 days, the decline that you see in that portion of the well are generally a little more steeper than you do when you get into finally running tube and gas lift, et cetera.

And this deals with the fact that five and half case is pretty large and just you get slug flow, you get a bunch of different things going on. So we have seen that, in our opinion, we have seeing the full benefit yet of the 10,000 foot lateral.

We did run tubing about a week ago and even before putting the gas lift to the well, which we have now, we saw an uplift in overall production performance and we have been on for a week now and the wells have been pretty flat and so we will need to see now what happens from here.

But if you look at the offset wells around us, regardless of lateral length, when you finally run tubing and you put whatever pumps, whether its EPS or gas lift, you do get an uplift, you do get a flattening of the curve and so we will now have to look at this portion of the curve. But so far I would say that we are pleased with the results..

Okay great and then lastly, just as it relates to with Nobles acquisition closing, time of actual acquisition closing [indiscernible] right around you, its seemingly a lot more activity in your particular portion of the Delaware basin.

Any color in terms of increased activity and any potential impacts that may have on your ability to access the completion services..

Ron I would say some of the operators you have mentioned that are around us, they have contracted, or got term contracts with some of the service providers and the activity has increased around us, but we haven’t been giving any concern I guess that we would not have access to these vendors. But Jim do you have other comments..

I would say that as long as we have a rig program that consistent, we can plan the future.

We obviously have to kind work with the service providers in getting in line, and getting our future dates established, but we have been able to do that and as Allan said earlier, within about 30 days of when we are getting the rig off location, we are ready to do fracs that we have been able to get our dates and we have our future dates set now.

So we are not seeing it at this point..

Great. Thank you so much..

[Operator Instructions] We will go next to the line of Kyle Rhodes with RBC. Please go ahead..

Hey good morning guys and apology if I missed any of this during the prepared comment, but just curious if you could provide some color on how the Rude Ram and Ripper State wells compared to the Lonestar wells at this point and flow back, I know it's still creaming up, but just curious how those are tracking versus your first well..

Yes. They are very comparable comp, they are kind tracking how the first well [indiscernible], so they aren’t pleased with that so far..

Got it and is the Gunfighter - is that kind of your base line for expectations going forward?.

This certainly have, its early I would say and we are still experimenting with our completion, but if that’s the answer we get and we will pretty pleased with it, we always hope to improve upon that but so far so good..

That’s great and just one on well cost, curious how those last two wells came in versus the 10.2 million AFE and then may be what you are expecting on AFE to the rest of the year. I know you would you mentioned some service cost inflation expected in the back for the year. So just curious how those came in and where its trending..

Yes. The Rude Ram and the Ripper State both of those wells were within 10.2….

We were a little higher than that because we added the nano materials to the completion process, but as far as drilling and completion they weren’t significantly different from that. They were in that ballpark. Yes. So one was a little bit higher and the other was a little bit lower and so in the average they were right about that.

Then on the Rude Ram and Reaper Well [Indiscernible] vertical well that's not a very good comparison and then we will certainly try to keep those cost down in this Gunfighter well that we are drilling now, but service costs have increased, rig rates, tubular kind of with our spectrum of costs have increased out here due to the large demand by offset operators..

Got it.

So may be a little higher than 10.2 million AFEs are may be partially offset by some improved efficiency is the kind of right way to think about it?.

Yes, and chronologically the one that was a little bit higher was the first one and the one that was a little bit lower was the second one..

Got it, that's helpful. Thanks guys..

Thank you..

At this time, we have no further questions. So I would like turn it back over to Allan Keel..

We do appreciate everyone participating in the call today and we look forward to update as we proceed in our development out here. So again, thanks so much..

We would like to thank everybody for their participation. Please feel free to disconnect at any time..