Joe Grady – Senior Vice President and Chief Financial Officer Allan Keel – President and Chief Executive Officer Steve Mengle – Senior Vice President, Engineering Carl Isaac – Senior Vice President, Operations.

Neal Dingmann – SunTrust Kyle Rhodes – RBC Noel Parks – Ladenburg Thalmann Ron Mills – Johnson Rice.

Good day and welcome to the Contango's Results for Fourth Quarter and Year-End 2015 Conference Call. As a reminder, today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Joe Grady. Please go ahead, sir..

Thank you, Keith, and good morning to everybody. I'd like to welcome everyone to Contango's earnings call for the quarter ended December 31, 2015.

On the call today are myself; Allan Keel, our President and CEO; Steve Mengle, our Senior Vice President of Engineering; Tommy Atkins, our Senior Vice President of Exploration; and Carl Isaac, our Senior VP of Operations.

I’ll give a brief overview of the financial results, then I’ll turn it over to Allan to give you a brief overview of our operations and then we’ll open it up for Q&A.

And to remind everyone, as typical for most companies, we will limit questions to those from analysts that follow our stock closely as we believe that that is most constructive and productive use of everyone's time.

Before we start, 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 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, our net financial results for the quarter reflected the continuing softness in commodity prices and the related reduction in our capital activity under our conservative CapEx strategy.

We experienced lower revenue and producing property impairments, both of which were a function in large part to lower prices for oil commodities. As noted in our release, we also recognized the impact of an impairment by Exaro Energy, where we own at 37% stake and recognized a charge related to an unsuccessful acquisition effort.

All of those negative factors overshadowed meaningful improvement we have made in reducing our LOE and G&A cost, improvements, which we will discuss momentarily, and which have been incorporated in our guidance.

Net loss for the quarter was $111.3 million, or $5.85 per share, compared to a net loss of approximately $20 million in the prior year quarter. Excluding the impairment charges in both periods and the forfeited deposit, the net loss for the quarter pre-tax was $41.6 million compared to a pre-tax loss of $6.2 million in last year’s quarter.

Adjusted EBITDAX, as we defined in our release, was approximately $5.5 million or $11.1 million excluding the forfeited deposit, which we recorded as other expense, or $0.29 per basic share for the current quarter, $0.58 per share excluding the deposit charge, compared to approximately $34.8 million, or $1.83 per share for the prior year quarter, a decline attributable primarily to lower revenues, but offset in part by the lower lease operating and cash G&A expenses.

Cash flow per share on a recurring basis, meaning excluding the other expense, was approximately $0.54 per share, which was in line with consensus estimates.

To illustrate the benefit coming from our emphasis on cost improvement, quarter-over-quarter we’ve reduced cash G&A costs – or just cash cost, excuse me, and that is LOE excluding production and ad valorem taxes and recurring cash G&A, by 30% and our unit of production cost by almost 15%, despite an 18% decrease in production.

We stay focused on further improvement. Production for the quarter was approximately 8 Bcfe, or 86.7 million cubic feet per day, compared to 9.8 Bcf, or 106 million per day, in the prior year quarter and that was within company’s guidance.

As previously communicated, we continue to exercise discipline in our CapEx strategy by reducing our program to include only strategic drilling for derisking new ideas and have deemphasized the expenditure of capital on what are marginally economic projects in this price environment merely to reflect production growth.

Consequently, new production from oil and liquids-weighted drilling has not been sufficient enough to offset higher rate gas production from our GOM properties period-over-period. We have provided guidance of 77 million to 82 million a day equivalent for the first quarter of 2016 with roughly the same commodity mix as in the most recent quarter.

Commodity prices during the quarter were between 40% and 50% below prior levels for all products. Our weighted average equivalent price declined 48% from $5.14 per equivalent to $2.69 per Mcf equivalent. Lower prices contributed to over 60% of the total decrease in revenue compared to the prior year quarter.

In January of this year, we entered into swaps on approximately 60% of our forecasted PDP production for February through December at a fixed price of $2.53 per MMBtu.

Total lease operating cost, excluding production and ad valorem taxes, were approximately $6.9 million for the quarter, compared to $8.6 million in the prior year quarter, an approximately 20% improvement.

We continue to identify and pursue opportunities to reduce field operating costs through efficiencies as well as concessions from our service providers. Guidance for the first quarter of 2016 is $7 million to $7.5 million, excluding production and ad valorem taxes.

Non-cash impairment expense in the current quarter was a total of approximately $48 million, $42 million of which was related to producing properties and approximately $6 million, which related to unproved prospects and expiring leases.

And substantially all of that is related directly, as in producing properties, or indirectly for the unproved acreage to the decline in commodity prices.

As everyone knows GAAP requires the impairment of the carrying value of individual assets, where the carrying value of that asset exceeded the estimated risk, discounted future cash flows from reserves due to the low price environment.

Exclusive of non-cash stock compensation, cash G&A expense was $2.2 million for the current year quarter, or $0.28 per Mcfe, compared to $6.4 million after adjustment for stock comp for the prior quarter, a decrease resulting from lower incentive based bonuses in 2015 of $1.7 million, reduced staff related to a reduction in force, which I I'll mention in a minute, of about $1 million net, and lower legal and franchise taxes – legal fees and franchise taxes.

Just as we have done in the field, we have emphasized internally the need to reduce administrative costs and accordingly, in August of this year we implemented a reduction in force in our corporate offices and reduced head count by about 30%. Guidance for the first quarter is $4 million to $4.5 million in cash G&A.

Loss from affiliates for the current year quarter was approximately $30 million, compared to a gain of $2.5 million in the prior-year quarter, with substantially all of that difference related to a non-cash impairment charge related to the reduction in carrying value of Exaro's assets, due to the reduction of various reserves in this low price environment.

We had approximately $150 million outstanding on our credit facility at year-end and had additional borrowing capacity of approximately $73 million under our $190 million borrowing base. Our next regularly scheduled borrowing base re-determination is May 1, 2016, and we've just gotten started on that process.

We expect some reduction in the borrowing base due to commodity prices and reduced drilling program but have no guidance from our bank group at this time as to what that reduction might be.

As disclosed in our release a couple of weeks ago, CapEx activity for 2016 is currently forecasted to consist of the completion of the Christensen 1H well in the Muddy formation in Weston County, Wyoming, which is our third well in this play and lease extensions in the area and in Southeast Texas.

Our total CapEx program for 2016 is currently estimated to be very minimal. However, if commodity prices improve, we have the inventory available to re-engage in an active drilling program in both our Madison and Grimes County and Wyoming areas. That concludes the financial review and I'll now turn it over to Allan for an operations update..

Thanks, Joe. Good morning, everyone, and thanks for being with us today. I'd like to give you a brief update on our operations during the quarter. As most of you know, it's a period that posed a lot of challenges within the industry as well as Contango. In general, we don't have a lot of operational information to share this morning.

It was a pretty quiet fourth quarter from a capital perspective and will likely be very quiet here in the first quarter as well due to limited economics associated with most everyone's inventory during this low price environment. It's going to continue to be our strategy to preserve capital and keep our balance sheet in the good position.

We continue to be impacted by these low prices just like everyone else. While we must continue to deal with it on existing operations, we do believe that those with a solid balance sheet, financial condition might be able to take advantage during this period if it continues to persist.

As I said, we'll be conservative with our capital program and remain focused on utilizing our excess cash flow to reduce debt, both of which both allows us to maintain our flexibility to pursue growth through drilling our existing inventory of a process recover or potentially being able to capitalize on acquisition opportunities that may surface as the year progresses.

Regarding our drilling program, during the quarter we completed Popham well, our second well in our North Cheyenne Muddy Sandstone play in Wyoming. We did utilize a more robust frac recipe than we used in the original well, the Elliott well that we drilled out there. The results today on the Popham have exceeded those of our initial Elliott well.

We're currently completing the Christensen 1, which is our third well in the area and are using enhanced version of the frac recipe we used in the Popham well. We will report results on that well in our next operations update that will likely be in early May.

As you know, we have roughly 35,000 net acres in the area and anticipate being able to keep that acreage position together, given that we have three to five year leases and there are some extensions that will have to be done, but overall we feel very comfortable with our ability to keep that acreage position intact.

As far as other areas as well, we still feel very strongly about our position in the Madison Grimes County area, where we've got roughly 16,500 acres. We have stack potential there in different formations.

So far we've exported the Woodbine/Lewisville formations, but we still believe there's a meaningful upside in the Eagle Ford, lower Lewisville and Buda in a better price environment. Joe mentioned our cost reduction efforts.

We've continued our cost reduction efforts in each and every aspect of our business in drilling and completing, in field operations and then in the corporate office as well.

Again, as Joe mentioned our recurring period-over-period LOE costs for this quarter were down by approximately 20% and our goal is to get our cash G&A cost down by 30% or more, commensurate with the reduction in headcount as the initiatives put in place start to provide full benefit.

We'll continue to identify additional areas for cost improvement and we'll continue to press our suppliers, vendors for concessions as well. Joe mentioned it, our acquisition efforts. We think that the market is beginning to become more attractive for someone like us who is in a good financial position, use our balance sheet.

In 2015, we analyzed numerous opportunities, did not get to the finish line as prices continued to deteriorate throughout the year, found several things that we really liked to do. There was just a disconnect between the buyer and the seller on price.

But we think the market forces have – will continue to force people to look at alternatives for – to raise additional capital, whether it’s asset sales or, in the case of some companies, that may result in having to combine or merge with a more stronger entity.

I would say in summary, we anticipate that this low commodity price environment could be with us for a little bit longer as a lot of people are predicting, so we believe the appropriate near-term strategy is to be conservative in drilling, preserve our acreage through extensions of our core positions that show – that have meaningful upside potential, and where appropriate, use our excess cash flow to reduce debt.

We’ll try to take advantage of the market again as far as acquisitions and combinations go, but we do believe that we’re only going to pursue those that are accretive to our shareholders and that are on prudent terms. So that’s just a quick overview from me this morning. I think that concludes our remarks.

With that, operator, I’ll turn the line over to you for questions..

[Operator Instructions] We’ll take our first question from Neal Dingmann with SunTrust. Please go ahead..

Good morning, guys. I’m sure a question you and Joe get a lot, just you’ve prudently dialed back here, just your thoughts between looking at Madison, Wyoming, and Elm Hills and these areas, of what it would take.

Is it a price that you enjoy looking forward to become a bit more active there? Is it a rate of return that you’re kind of shooting for? How should we think about what it would take to bring some activity back to one of these areas?.

Yes. I think from my perspective, Neal, we would look at rate of return on – at the individual well level to determine whether or not we would want to put the money in the ground. We do look at production.

At some point, we need to add to our production and reserves, but at this stage we just don’t see it being all that prudent to put capital in the ground. Joe, any other thoughts..

No, I think that’s a good assessment..

And then guys, let me just add, I just had one more, just I’m sure you get a lot of, Allan, today about M&A, but how do you compare, again, as far as thinking about adding and bringing more activity back versus M&A? It seems like the spread, as you pointed out, I think is still pretty wide out there.

Again, M&A versus sort of ramping your organic production, how do you sort of think about those two things?.

Well, I think that in the past year, as in 2015, still thought that there was a pretty big gap between the buyer and the seller. We think that narrowed. We think that there are going to be numerous opportunities in the market this year. It’s a question of, okay, how do you accomplish, get an acquisition done or what form of currency do you use.

We think there is going to be plenty of opportunity for us to pursue this year and I think we’re focused on that. If prices were to continue to see improvement, we do have the inventory. We have stuff in Madison Grimes that we can go do.

We have – our original budget for this year when we first proposed it was fairly substantial but things declined during the latter half of 2015 and into early 2016, we just said, hey, let’s continue to hold our line here and let’s just wait until things get – turn around. It may be some time before they do.

We’ve seen some positive movement in prices lately, but at least on the oil side, not as much on gas, but most of our drilling opportunity is oil based. We don’t have that much in terms of gas.

I would say that we’re anxious to get drilling and be active again because that’s what we do for a living, but I think the better opportunity’s going to be on the acquisition of assets side..

Got it. Thanks very much. Thanks for the details..

We can take our next questions from Kyle Rhodes with RBC..

Hey, good morning, guys..

Good morning, Kyle..

Any more color you can provide on the acquisition you decided not to pursue in the fourth quarter, just maybe in terms of location, size or HPP commitments, just to give us a flavor of what you guys were looking at and then maybe what ultimately led you not to execute the deal?.

Sure. The opportunity we were pursuing was in West Texas. It was oil. It was a very attractive opportunity. Just disconnect between us and the seller, which was surprising to us at the end but nonetheless it didn’t happen. We felt like it would provide us with a runway of drilling inventory that was economic at substantially lower prices.

So yes, it was a very – we thought a very nice opportunity but couldn’t get there with the seller at the end.

Joe, any other comments on that?.

No, I think that was a good overview of it. It was – the important thing for us it was a good combination of producing properties as well as upside that we would have drilled in this price environment. That’s why it was so attractive to us..

Got it. That’s very helpful. I guess just you mentioned on your 2016 hedge book coverage roughly 60% of the forecasted PDP gas production.

How should we be thinking about your base kind of oil production decline in 2016? Should we expect kind of – should we model kind of similar to the implied 18%, 20% year-over-year decline you’re sitting on the gas side, or how should we think about that?.

I think on the oil side, it’s probably pretty flat. On the gas side, offshore is maybe 15% in total, 15% to maybe a little bit of a decline on oil.

Steve?.

I was going to say we grew sort of core Bcf last year and it’s our budget year, so it’s 20%..

Okay. [indiscernible] About 20%. We don’t give formal guidance, but that’s – for the year, but that’s probably good soft guidance..

Okay. Got it. That’s helpful.

Any update you can give on the Popham well in Wyoming? Maybe just kind of a current production rate there and how it’s tracking versus your type curve?.

Well, at the moment it’s shut in. As we speak, it’s shut in. We had some part of rods we’re fixing. It was shut in while we were fracking the Christensen well. So far, it’s still on our type curve and keep in mind, the Christensen’s our third well so we’re still – we still look at the type curve every day.

We’re somewhere – we think ultimately we’ll end up somewhere in the 300,000 to 350,000 barrel range today and maybe better. But we’ll see. The Christensen is going to be an important well. The Popham seems to be holding up pretty well..

Got it.

Can you remind me the AFE on the Christensen?.

The AFE on the Christensen well?.

Yes..

I think the way to answer that question is, we’ve done our projections kind of going back up the oil curve including where we are today and right now we’re projecting about a $5.5 million all-in drill complete facility cost at roughly a $45 oil market.

We’ve been spending a lot of time trying to understand what the capital requirements will look like as we come out of this – these low oil markets so we have a clearer understanding of what the economic performance of these wells will be..

Thanks, guys..

We can take our next question from Noel Parks with Ladenburg Thalmann. Please go ahead..

Good morning..

Good morning, Noel..

Just a couple things. Wondering about at North Cheyenne, I know you’re going to be doing a little bit of paying for maintaining leases.

Is there any additional lease availability to speak of in that area?.

Not really, no. From our perspective, we’ve got plenty to keep us busy once we get re-engaged in drilling, once prices improve. So leasing anything in addition to that at this point is probably a little premature given where – we’ve only got two wells under our belt and the third one about to come here on before long..

Sure, sure.

On the CapEx side, the amounts you’ve talked about being in view so far, do you have any sense of kind of what a baseline of sort of maintenance CapEx might be even if you don’t really have any drill bid activity later in the year?.

Well, we’ve got that all included in the number, if you will, that I quoted as being minimal. Our total CapEx for the year is less than $10 million..

Okay. Great. Great. You’ve had – a housekeeping item, just a number I was trying to work out between the full-year and quarter numbers.

The tax item in fourth quarter, was that – the tax provision, was that all deferred or was some of that cash?.

It’s all deferred..

Okay, great..

And will be going forward..

Okay. Great. I guess one last thing about the acquisition you were working on in fourth quarter.

Was that an opportunity that was brought to you by a broker or an intermediary or was it something that happened out of direct contact?.

It was a competitive bid process..

Okay.

So the properties actually did – there actually was a transaction at the end of the process?.

Not that we’re aware of, no..

Oh, there was not. Okay. So they took it off. Okay..

Yes, right..

Okay. Great. That’s all from me..

Thanks, Noel..

And our next question comes from Ron Mills with Johnson Rice..

Morning, guys..

Hey, Ron..

Good job on the cost side. Question, particularly the G&A is going to be pretty sticky because of the reductions.

On the LOE side, talk about some of the things that you have done to improve the LOE and how much of those are – would be sustainable in a higher cost environment?.

This is Carl Isaac. I guess the place to start is that we’ve always managed our LOE pretty closely and kept a very close eye on it. It’s one of our drivers. Regardless of the price of oil or gas, it’s something we’ve continually done.

What we’ve done a lot of is we’ve made sure we understand what the markets are, whether it’s for compression services or maintenance contracts, chemicals, obviously, salt water disposal, marketing, repairs and maintenance, all of these things we’ve gone back and visited on a routine basis historically and as the price of oil has declined, we’ve stayed in the market and understood kind of what the service markets were offering and made sure that we were benefiting from those reductions on the LOE side.

I think by and large we’ve seen the biggest reductions and I think those will start to taper off but even at that, we feel like we can safely expect to reduce our LOE another 10% this year on an apples-to-apples basis.

The one thing that I would point out that the 20% reduction that we’ve been talking about was really not apples-to-apples because we added LOEs, so to speak, onshore both in Texas and Wyoming but still experienced a 20% reduction overall..

Okay.

In Wyoming, you said less than $10 million, Joe, but where is the majority of your lease maintenance capital? Is it in Wyoming this year? Is it in Madison Grimes? I guess another way, how much leases kind of are coming up this year for extension/renewal?.

It’s a total of probably $3 million, little over $3 million, Ron, and two-thirds of that is in Wyoming and that extends for three to five years a large portion of our acreage..

And can you just talk about, in a more normalized environment, you talk about being able to get back to work and having a deep inventory, just a reminder of inventory by area. I think in Wyoming potentially 200 or 300 locations.

A, is that correct and B, how about in East Texas?.

Well, the 200 to 300 in Wyoming is right. Southeast Texas, Madison and Grimes, on all – for all formations, 100. Maybe a little more than that..

Ron, I would say that in the Madison, Grimes County area we broke it down between the Woodbine, the Lewisville and then the Eagle Ford, which we, as you know, we haven’t drilled yet and that activity has kind of come closer to our acreage now and feel like that’s something that’s – we haven’t really outlined in detail.

We have a general view on what the number of locations are there, but as that activity has encroached upon us, we now see where we do have quite a bit of potential, both in our Northern tier of acreage, up and around the Chalktown area and Force area, but also down in the Grimes County acreage as well, where Apache and others are nearby.

So I would say that the overall – in terms of overall locations, it’s well over 100 if you include all formations and could be double that with the Eagle Ford..

Great. And then a clarification on the deposit forfeiture. What does the process work? If the seller goes through a bid process, someone makes a bid, the transaction doesn’t close, was there a particular reason the transaction didn’t close or if – because if they pulled the package, I would assume that, that charge wouldn’t have been made.

Is that a fair assessment?.

Yes, Ron, it was – we, at the end of the day in the face of falling oil prices and a dramatic increase in the financing markets, we were not comfortable with proceeding at the price that we originally bid and the seller was not receptive to any reduction that would give us comfort in going forward..

Understood. Lastly, just on the balance sheet, the $115 million of borrowings on your revolver, what are some of the covenants there? I assume with the plan to pay down some of the revolver with free cash flow that you shouldn’t have any issues there..

Well, the covenants are the standard leverage ratio and the current ratio are about it. Leverage ratio is 3.5 times. I think we’re a little less than 2 at this point. And in good shape on the current ratio, so we don’t have any covenant issues..

All right, guys. Hey, thank you so much..

Thank you..

It appears we have no further questions. I’ll return the program to Allan Keel for closing comments..

We’d like to thank everybody for joining us today and look forward to catching up with you next quarter to give you updates on our Christensen well and any other activity that we may have between now and then and thanks again for your interest. That concludes our remarks..

Ladies and gentlemen, this does conclude today’s program. Thanks for your participation. You may now disconnect. Have a great day..