Operator:Good day, and welcome to today’s Contango Oil & Gas Results for the 4th quarter and year end 2016.  Today’s conference is being recorded.  At this time, it is my pleasure to turn the conference over to Joe Grady, Chief Financial Officer.  Please go ahead.

Joe Grady:    Thank you.  Like to welcome everyone to Contango’s earnings call for the fourth quarter of 2016.  On the call today are myself; Allan  Keel, President CEO; Steve Mengle, Senior VP of Engineering; Tommy Atkins, Senior VP of Exploration, and Jim Metcalf, Senior VP of Operations.  Now 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 will follow it with a Q&A.  And just as a reminder, and as typical for most companies, in the Q&A we will limit questions to those from analysts that follow our stock as we believe 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 the Securities Exchange Commission which may include comments or 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.

Now 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 of the prior year quarter.

As you noted in our release, if you eliminate all of the noise related to impairments caused by the commodity price environment, and the forfeited acquisition deposit in 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 quarter.

Adjusted EBITDAX, a measure of operational cash flow, as we define in our release, was approximately $8.2 million for the current quarter, compared with $7.5 million for the prior quarter.

The current year quarter was aided by a $1.6 million in lower operating expenses, that was more than offset by $1.5 million in incremental accretive incentive compensation and $2.7 million in realized hedging losses.  While the prior year quarter was negatively impacted by the forfeited acquisition deposit, after adjusting for those special items in each period, recurring adjusted EBITDAX was relatively flat at $12.4 million and $13 million for the 2016 and 2015 quarters respectively.  Cash flow per share was approximately $0.30 per share for the quarter, which was consistent with consensus estimates.

Production for the current quarter was approximately 5.9 BCFE, or $64.3 million equivalent per day, compared to approximately $86.7 million per day in the prior year quarter, which was an expected decline due to our suspension of drilling for the last year and a half in response to the low and uncertain commodity price environment.  Our production was within guidance of 63-68 million a day, and only slightly below consensus estimates of 65.3.  And that performance was despite about 1.6 million a day impact for the quarter related to wells that were shut in[?] for work over[?].  Guidance provided for the first quarter 2017 incorporates the loss of an estimated 1.3 million per day for the quarter, due to compressor failure at Eugene Island 11 that has since been replaced and production has been restored at pre-failure rates.

Also incorporated in the 2017 first quarter guidance is a partial loss of production from our Lonestar-Gunfighter No.1 well, our first well in our Southern Delaware Basin acreage.  But production from the other three wells currently in process is not contemplated to commence until the second quarter.

As the quarter neared its close, we took advantage of the spike in commodity prices to enhance our hedge position for 2017, to protect the portion of our calendar 2017 cash flow, and therefore capex budget, resulting in approximately 50% of our remaining forecasted PDP

natural gas production being hedged at a weighted average floor of $3. And 54% of our remaining 2017 forecasted PDP oil[?] production being hedged at an average floor of $55.14.

Total LOE expense at 5.9 for the quarter, which is inclusive of production taxes, was below guidance as we continue to find ways to reduce cost and operate more efficiently.  Guidance given of approximately 6.4-7 for the LOE – for LOE for the first quarter ‘17, is a little higher than that due to anticipated work overs in our Southeast Texas area.

On the capex front, we initiated our Southern Delaware Basin program, and also were successful in increasing our net acreage position from an initial 5,000 net acres to approximately 6,600 net acres through today.  As noted in our previous release, we will focus on Pecos County for all of 2017, including reassessing as we go along the pace with which we will drill for the remainder of the year.  We currently have approximately $54 million outstanding on our credit facility, which has a borrowing[?] base of $140 million, so we possess the capacity to accelerate drilling in that area if deemed appropriate during the year.

That concludes the financial review and I will now turn it to Allan for an operations update.

Allan Keel:Thanks, Joe, and good morning everyone.  Thanks for being with us today.  Joe has just mentioned we have 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 noted in some of our previous releases, you know, we were very pleased to have found an opportunity to get into, you know, what is probably considered to be 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 spud our first well during the fourth quarter last year but that went on production late January and we have three more in varying stages of drilling or completion at this time.  We have also exercised our [inaudible] option to drill our fifth well to be coming up soon.  We anticipate having three more wells in production during the second quarter.  All these wells include a 10,000-foot lateral with roughly 50 stages of frac.  Our fourth well, the Grim Reaper No.1, which we are drilling[?] now will also include a pilot hole that we hope to get good information from, you know, potentially productive zones throughout the column.    

We will evaluate results along the way, and continually review our strategy for the remainder of the year, but this time is to continue developing our acreage that we have, which as Joe has mentioned, it’s gross over 13,000 acres now.  So we have been able to add to that position some as we moved along since last summer, so, very, very happy about that. 

You saw in our release that our 24hr IP on the Lonestar-Gunfighter well was just under a thousand barrels equivalent per day, which we were very pleased with that being our first well.  And as of the day the release, we were still producing an approximate rate of 846 barrels equivalent a day, which was about 19 days after the 24hr rate was measured so, again, pleased with the results from that first well.

The next two wells are Rude Ram and the Ripper well, the completion on these two wells commenced yesterday and it would take about four weeks to complete that process.  Completion of the Grim Reaper well, the well where we are drilling a pilot hole currently, we used the same vendor as we were using for the Rude Ram and Ripper wells, and that completion date is scheduled for early May.  But after completion of each of these wells, we will likely commence production in a similar fashion to that of the Lonestar-Gunfighter, that is a controlled float process, slowly increasing the choke along the way.  As  Joe mentioned, we have been successful in increasing our acreage position by 30%, so we are at 6,600 net acres right now.  So as operator, we control approximately 13,200 gross operator acres.  And as we said before, with over 200 gross drilling locations from the Upper Wolfcamp and Second  Bone Springs.

And our acreage is setup very well, we have got the ability to drill 10,000 foot laterals on just about all of our locations.  We are assuming 1,000-foot spacing at this time but we will monitor that, see if that changes over time.  So, all in all, we are very excited about our program.  We believe that we have been fairly conservative in quantifying the potential for the Wolfcamp and the Bone Springs section.  There is a very thick stratigraphic column, is [inaudible], so we are very pleased about that.  So we are going to continue to evaluate, and some of these pilot holes will get logs and cores to help better understand and evaluate the entire stratigraphic column.

So with that, let us open up for some questions.  So, operator, can you just tee them up?

Operator:Thank you.  At this time if you do wish to queue up for a question you can do so by pressing the star key followed by the digit one on your telephone keypad.  If you are using a speaker phone, please make sure that your mute function is turned off to allow your signal to reach our equipment.  Once again, please press star one at this time to signal for a question and we will pause for a moment to allow everyone an opportunity to signal.

We will take our first question from Garth Grillo at Suntrust

Neil:Morning, guys, it’s actually Neil.  Allan, a question.  You know, you have lined up now maybe perhaps up to the fifth well.  You talked about – I know you have not put out really any guidance beyond that – talk about permitting – you know, if you were to decide to keep that rig after that.  Is that possible?  Or maybe if you talked about, I guess, what is your alternative or what is your options after that fifth well?

Allan Keel:You know, we’ve got a continuous option on that rig.  So it is our intent to keep it active throughout the years.  It is just, you know, we are watching both commodity prices and service costs, and results from our wells, so, so far so good.  For the most part, you know, 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, you know, we are encouraged by our results, we are encouraged by our ability to add acreage in and around our position.  But, you know, we always have to be cognizant of, you know, what is going on in the commodity market and also, you know, what the service side looks like as well.

Neil:And, on that rig you have the option, are just kind of paying well by well?  And you talked about, I guess why I am asking that just about service costs billed[?] on the, not just the rig side but completion side as well which you anticipate.

Allan Keel:Yeah, yeah, we do have, you know, an option, continued option to keep the rig, which we plan to do.  And then, in terms of service costs, we certainly have seen, you know, the increase as other have said, spoken to.  You know, kind of given what commodity prices are doing.  We will be interested to watch along with others as to see how that plays out over time but yeah we have seen service costs increase kind of across all segments of the service side

so, you know, I think it will be interesting to see what happens with tubulars[?], you know, obviously rig rates have gone up and all those things have moved up so, you know, we will continue to monitor that very closely as you can imagine.

Neil:Okay, and then just lastly, M&A, you know.  Some suggest, you know, there is a lot of things about, not as much out there, but again it seems like, you know, you seem to still see a lot of things available.  Just talk about M&A, and are you looking – if there is – are you looking to just particular in that Southern Del[?] where you are already at?  Would you be looking at the entire Perm to see if there is anything you can add to that?

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

Neil:Perfect.  I look forward to all that activity.  Thanks.

Allan Keel:Thanks, Neil.

Operator:We will take our next question from Kyle Rhodes at RBC.

Kyle Rhodes:Hey, good morning, guys.

Allan Keel:Morning, Kyle.

Kyle Rhodes:Just going back to Allan’s comment on the additional acreage you guys picked up.  The 1,600 acres kind of [inaudible] in the Delaware?  Any details you can give on price you paid for that?  Was it close to your initial entry price?  I just kind of wondering what the current pricing is out there.

Allan Keel:Yeah, it is, as you know, Kyle, it is very competitive.  You know the price we are paying is, you know, not too dissimilar from what we paid in our acquisition back last summer.  But certainly, given what has happened around us where these, you know, larger packages have gone for $30,000 an acre, or greater in some cases.  It makes it difficult to try to kind of, you know, add acreage in big blocks because, you know, people obviously want to get paid for that.

Kyle Rhodes:Yeah, it makes sense.  And then let me ask a question on Fly 9.  I notice you guys are drilling your laterals east to west, in most industry 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?

Allan Keel: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 are all about, you know, you can make a case for either way.  And our acreage sets up perfectly to drill east-west laterals 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-west was a little bit better.

Kyle Rhodes:Got it.  Okay,  and then can you just let us know how the Lonestar Well cost kind of came in versus expectations, and then just kind of circling back to the service cost inflation theme, remind us that kind of what is baked into the budget from an expectation of service cost inflation standpoint?

Allan Keel:Yeah, so, originally, last July, when, you know, industry was dead.  You know, we were thinking these wells would be, you know, $8-8.5 million to drill and complete, and hook up, and so, we, you know, as time went by, we started getting, you know, active, and people became more active.  So by the time, you know, December rolled around, you know, that $8.5 million well, you know, slid to, you know, really like a 10.2, primarily driven by completion

costs increase.  Not really as much as a rig or anything else.  And that is, you know, kind of the number we are using in our budget, even though, you know, we have been, we have seen additional cost [inaudible] and we anticipate that to continue if prices – if commodity prices, you know, stay in that $50 price range.  There is a lot of demand, and, you know, the way people are, you know, there’s not that much supply when it comes to, you know, [inaudible].    

So, we anticipate there will be some additional cost creep, but we are keeping our flexibility in terms of how much we are committing to at any one time.  Relative to the first well, we, you know, that was our first well.   We had some mechanical issues with our first well so we came in above our costs, but on the next two wells we were basically at the [inaudible] number that we put out, so making progress.  The fourth well we drilled a pilot hole.  We are going to do some additional testing and science on that so definitely it may end up costing a little bit more than the – our [inaudible] but generally, that is what we are seeing.

Kyle Rhodes:Got it.  And then just one more high-level strategic question, if I could, you know, given that you guys are trading roughly at PDP, you know, PV10 value at the strip.  You know, what is the strategy for getting more valuation credit for your Permian[?] acreage?  Is it just simply executing and hitting your targets in terms of well cost and timing, or is there anything else you guys are looking to do to kind of get more credit up there?

Allan Keel:Yeah, you kind of hit the nail on the head.  We are trading at a pretty significant discount to our, you know, PV10 value, especially if you look at the five-year strip.  We are, you know, significantly discounted.  So, you know, yeah, we are getting in front of investors, and trying to talk to them to help them understand what we are doing, what the economics of the play are, you know, what our value company-wide looks like.  Cash flow coming off our other assets especially Gulf of Mexico. 

That is always a question as to – but what is your strategy?  What is your long-term strategy?  Well, our strategy is to make money first and foremost, but in terms of how we get there, you know, I think people would prefer for us to have a single-basin focus, but, you know, we have

got great cash flow from the Gulf of Mexico, and we are going to continue to use that cash flow to develop our assets.  And right now, Southern Delaware is, you know, a premier asset, you know, not only for us but for those people that are active in West Texas so.  That is kind of our strategy, is just to get in front of more investors and just tell them our story and really execute and show them our results.

Kyle Rhodes:Great guys, that’s it from me, appreciate the color.

Operator:We will take our next question from Ron Mills at Johnson Rice.

Ron Mills:Morning guys, question on the well, you know you talked about the IP rate – almost 1,000 barrels a day still producing in the mid-800s.  You talked about, you know, the performance of that well versus the type[?] curve that you originally presented in your acquisition presentation, and maybe some other details of how you are flowing it back to try to compete with the type curve you had originally put out?

Allan Keel:Yeah, so in terms of Ron are you asking us how do we feel about that first well relative to our initial  –

Ron Mills:Versus your...  exactly.  Exactly.

Allan Keel:Yeah, well I like it’s – I mean it is really early in the process.  I mean, if anything, you know, it is probably slightly below it but we are not really sure about that because, you know, it is just really early and the way we flow the well back, we could – you know, had a controlled flow back, whereas a lot of our offset[?] wells were, you know, pretty much open choke from the very beginning.  So, we are monitoring that and watching that pretty closely obviously, so I’d just say, you know, it is early.  That is all I would say there right now.

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

Allan Keel:Yup.  Yup.

Ron Mills:And then, in terms of activity, you know, it sounds like versus January the plan now is to keep that rig running, you know, 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?

Joe Grady:Well, Ron, you know, we originally had a pause in our budget.  But based off the results of the first well, and the fact that we think it is important to keep our service providers on our team, we decided the we’ll keep moving forward because we are excited about, you know, 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 will everything else hopefully.  But, like Allan said, we will continue to watch it all through the year, 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 our prices are better than we expect, you might see one.  But I think that it will be optimistic to plug that into your model at this point.

Ron Mills:Understood, but then from an overall well count standpoint, you know, how many wells do you think you will get in now[?] by not letting that rig go for that three or four-month period?

Joe Grady:Probably nine.

Ron Mills:Nine more in addition to the first four?

Joe Grady:No.  Nine in total for the year, for the calendar year.  So we’ll end up with total eleven or twelve by the end of the year.

Ron Mills:Okay.  And just from a financial standpoint, you talked about the liquidity under your revolver.  Is the plan still really to try to maintain it as close to cash flows and if you have some near-term draws that you would just utilize the revolver?

Joe Grady:That is always our strategy.  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 rig going for the whole year, we probably out spent some, but not a meaningful amount relative to our liquidity.

Ron Mills: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 released previously, correct?

Joe Grady:We include some in our capital budget already.  We had about $10 million of our original capital budget for acreage acquisitions in ‘17.

Ron Mills:Okay.  That is all I have.  Thank you, guys.

Joe Grady:Thanks, Ron.

Allan Keel:Thanks, Ron.

Operator:And at this time, we have no further questions so I would like to turn the conference back over to your hosts for any additional or closing remarks.

Allan Keel:Well, that is it.  Thanks so much for everyone’s participation and look forward to updating you soon.

Operator:This does conclude today’s conference.  Thank you for your participation.