Joe Grady - Chief Financial Officer Allan Keel - Chief Executive Officer Steve Mengle - Senior VP, Engineering Carl Isaac - Senior VP, Operations.

Chad Mabry - MLV & Co. Michael Glick - Johnson Rice.

Please standby. Good day. And welcome to the Contango Results for First Quarter 2014 Conference Call. Today’s conference is being recorded. At this time, I would like to turn the conference over to Joe Grady. Please go ahead..

Thank you, Jenny. I’d like to welcome everyone to Contango’s quarterly earnings call for the quarter ending March 31st. As you are aware, we changed our year end to a calendar year basis in conjunction with our merger with Crimson. So, this is our first -- truly first quarter results reporting for 2014.

As we have mentioned in our prior call, we complemented our transition report on Form 10-K, which is prescribed by the SEC, with our Form10-K/A that included audited calendar year end statements for the full year’s ending December 31, 2011 through 2013 and a Form 8-K that includes 12-month 2013 calendar year end financial statements pro forma for the Crimson merger assuming the merger was completed on January 1, 2013.

We made these two supplemental filings and our mechanism for use by the investment community in making current historical comparisons going forward. Our results for this quarter include post-merger results for the 2014 quarter, while the 2013 results are pre-merger standalone Contango.

I bring today as myself, Allan Keel, our CEO; Steve Mengle, our Senior VP of Engineering; and Carl Isaac, our Senior VP of Operations. I’ll start out with a review of the financial results, Allan will follow with an overview of our operations and then we’ll have a Q&A session after Allan.

We will limit our questions in the Q&A to those from analysts that follow our stock closely. As we like most companies, public companies limit questions to their group. As we believe that and this is most constructive and productive use of everyone’s time.

Before we begin, I want to remind everyone that the earnings release and the discussion this morning may contain forward-looking statements as defined by the Securities and Exchange Commission that include comments and assumption concerning Contango’s strategic plans, expectations and objectives for future operations.

Such statements are based on assumptions we believe to be appropriate under circumstances, however, those statements are just estimates are not guarantees of future performance or results and therefore, should be considered in that context.

As relates to financial results, Contango reported net loss of $10.2 million or $0.53 per basic and diluted share for the current quarter, compared to net income of $3.9 million or $0.25 per basic share for the standalone prior year quarter.

Included in the current quarter results, were total charges of $41.8 million in exploration expense and impairment expense, related to an unsuccessful exploratory well drilled in the shallow waters of Gulf of Mexico, as specifically you will hear in further comments the Ship Shoal 255 well.

Exclusive of those charges, we would reflect the net income before tax for the current of approximately $23 million, compared to net income before tax of $7.2 million for the prior year quarter. So that is in the offshore dry hole we had pretty good quarter.

Weighted average shares outstanding were 19 million and 15.2 million shares for the 2014 and 2013 quarter’s, respectively. Adjusted EBITDAX as we define in our release and which excludes exploration expense was $58 million for the current quarter, compared to $18.8 million for the prior year quarter.

Improvement due primarily -- due to the addition of the Crimson production base and to higher natural gas prices.

Production for the current quarter was approximately 10.6 Bcfe or just over 117.5 cubic feet equivalent per day, compared to just over 65 million per day equivalent in the prior year quarter, which is an overall 82% increase over the prior year quarter. The increase was primarily attributable to the merger.

However, we did reflect an increase in offshore production due to our acquisition of additional interest in December in our Dutch wells through the exercise of a preferential right to purchase and due to the fact that 2013 production was negatively impacted by the shutdown of Vermilion 170 well for most of that prior year quarter.

Production was also up almost 7% over the 2013 fourth quarter and was at the upper end of guidance for the current quarter due to success in our onshore drilling program. Guidance for the second quarter of 2014 is between $115 million and $125 million equivalents per day.

Prices were up 38% and down 12% for natural gas and oil, respectively, in the current quarter compared to the prior year.

On an equivalent unit basis, the weighted average price of $7.59 per Mcfe for the current quarter, compared to $5.47 per Mcfe for the prior years quarter, a 39% increase that reflected the fuel prices changes that I just mentioned.

But also reflects the increase in the mix of crude oil and liquids to our total production going from 35% from prior year quarter to 25%. Total operating costs in the current quarter, including direct LOE, expense workovers, production taxes and transportation costs were $5 per Mcfe, compared to a $68 per Mcfe in the 2013 quarter.

Negatively impacting the prior year quarter was $5.3 million in workover costs at Vermilion 170.

Exclusive of which the LOA per Mcfe for that year quarter would have been $0.78 per Mcfe and direct LOA and expense workover costs which is the previous number, I mentioned, exclusive of production taxes and insurance was $8.1 million for the quarter and at the lower end of guidance.

Our guidance for direct LOE including workovers for the second quarter is $8.3 million to $8.8 million. As mentioned earlier, we completed drilling the Ship Shoal 255 exploratory well in early May, resulting in a dry hole.

As we knew the result prior to filing of our 10-Q for the March quarter, we recognized the actual expenditures today to $331 as exploration expense.

We also recorded a total of $15.1 million in impairment of unproved cost during the quarter, related to the lease which was $3.5 million and two facilities that were to be used to produce the well of $11.6 million.

We also recognized -- we will recognize between $7 million and $9 million of additional exploration expense in the second quarter of 2014 for the expenditures spent on drilling and plugging well between at the end of the first quarter and finalization 12th May.

Cash G&A, exclusive of stock compensation expense was $9.4 million for the quarter, including $1.3 million in accrued merger related cost. Exclusive of this merger related cost, the quarter total of $8.1 million for cash G&A was slightly below the lower end of the guidance for the quarter.

We have provided guidance of $7.5 million to $8.5 million for the second quarter of this year. Capital expenditures for the fourth quarter was -- for the first quarter, sorry -- was $61 million, including $22 million incurred on Ship Shoal 255 well.

It incurred during the quarter the total of $26.7 million which you see on the income statement includes costs that were incurred in the fourth quarter of 2013. You will hear from Allan more detail about plans for the rest of the year.

However, in total, we expect to spend a total of $215 million to $225 million for the year with substantially all of that being funded through internally generated cash flow. At March 31st, we had approximately $64 million outstanding on our credit facility which has $275 million borrowing base that was recently reaffirmed through November 1st.

So we have very strong liquidity in financial position that provides us the flexibility to increase our capital program if we deem appropriately based on results and also capacity to pursue acquisition opportunity should we find the right one. That concludes the financial review. I will now turn it over to Allan for an operations update..

Thanks Joe and good morning everyone. Thanks for being with us this morning. And it has been a busy quarter for Contango in terms of the combined two entities and one cohesive group and that group has been started on active 2014 capital program. With the exception of the previously mentioned this formal Ship Shoal 255, it’s been a good quarter.

We remain committed to our previously detailed onshore program discussed on our last call and in our company presentation. But we decided further offshore exploratory activity to a later time which is consistent with our strategy to limit our dry holes exposure for any particular year.

Now, I’d like to share a few highlights about the information we provided in our operations release and where appropriate and meaningful, we will add a few extra comments.

In Madison and Grimes counties, Taxes, we continued to experience good results in drilling the Woodbine in our Force area, as evidenced by our three new wells brought on production and reported for the quarter, with two other wells in the early stages of flowback and another one awaiting completion.

We have continued to improve on a number of drilling/completion, completing days and cost in the area and therefore plan to drill another six wells during the remainder of the year.

Next-door, in our Chalktown area, we drilled on the Vick Trust B #1 in the first quarter, which happens to be looking like our best well in the entire Madison, Grimes area so far. We’ve just spud our next well there at the bore well in the area and expect to have a rig drilled in the Woodbine wells in Chalktown area for the remainder of the year.

Moving in south into Grimes County, we are preparing to drill the lateral into the Woodbine on our Tommie Carroll #2H well and have just completed a vertical pilot well from which we have recovered cores from the Eagle Ford section and other formations for analysis to potentially pursue drilling in those other formations in the near future.

Also as reported in the past, we will continue to monitor the two previously drilled Mosley down-space wells in the Force area and will await a final conclusion on what we think is a better way to maximize the events that are downspacing there.

As you recall, we have approximately 19,000 net acres in the Madison, Grimes country areas with numerous formations that are prospective and so we see this as the -- continue to be a very active area for the company in the foreseeable future.

Moving down to South Texas into the Buda formation, we also continue to drill and delineate this part of our portfolio. We completed and commenced production on all three wells and averaged additional rate, 30-day rate of about 430 barrels equivalent per day which represent about 80% all each.

We also have placed two other wells in that area on production recently, have one well in process and we will report those results in our next operations release. We do anticipate to have one to two rigs active here for the remainder of the year, as we continue to delineate our acreage position down there.

As you also might remember, we have dedicated some capital to James Lime up in the San Augustine area this year.

We started our program this quarter, drilling two wells into the James Lime, the first of which we reported initially 30-day IP rate of 832 barrels equivalent per day, which is about 6% of that stream was oil and the second of which is in the early stages of flowback.

We will monitor flowback results of these two wells for the next several months and then decide on whether to bring in a rig to accelerate development. Obviously, we are getting good flowback results and it’s just a matter or a question of the cost and return and things of that nature.

Other places that we are active or considering onshore, as most of you maybe aware, we have about 28,000 net acres in the TMS, that area that play has generated a lot of interest of late. Significant part of our acreage position is on western side of the current play. It’s generally in the area of the Mississippi river.

So we have roughly 20%, another 20% of Wilkinson country, our acreage is about 20%, Wilkinson County, Mississippi and the rest is in Felicia and St. Helena Parishes. We participated in a three team as well as a day including a 25% working interest in Crosby well and very minor interest in two others.

As we’ve indicated to people who asked us this question recently, we do believe that the drilling cost need to continue to come down dramatically and that the completion of practices need to be optimized before. We feel like we can achieve a return in this place that’s comparative with our other projects.

So we will continue to take away the approach before initiating any activity in this area. Also in our most recent operations release, we mentioned that we’ve entered into a deal or ownership with a private company. It’s a 50-50 exploration agreement. We’re acquiring acreage for another potential resource play.

We are not really prepared to talk a lot about that at this time, but we do anticipate being in a position to spud a well by the end of the third quarter. So we will keep you apprise on that as we can as we go forward. And finally, in the Gulf, as Joe mentioned earlier, the results of our Ship Shoal 255 well were disappointing.

We had not only the results but also the cost incurred, but we are in a process of constructing a single well structure for a tie in our two -- on our South Timb 17 discovery and that the expectation is that we will commence production by midyear.

We are also contemplating the commencement of compression installation, hookup on our Dutch wells at Eugene Island early third quarter. As I mentioned earlier, other than those two facility projects, we will defer the allocation of any more exploratory capital in the Gulf of Mexico until later date. So it’s been a busy quarter.

We’ve got a lot going on right now and we are trying to grow our position not only in our existing areas but looking for new as well. And that’s an update as we stand today and happy to take some questions now..

(Operator Instructions) And we will take our first question from Chad Mabry with MLV & Co. Please go ahead..

Thanks. Good morning. To start up with the Eugene Island, it looks like an encouraging initial rate on that Kodiak well.

Just curious how that compared to your internal model and maybe what you might need to see to accelerate activity in that play?.

I think with regard to our pre-drill estimate, we are a little lower on gas rate than we had expected, but on the other hand, we are a little bit higher on yield. And so I think we need to see which will surprise us. We need to see a little more history yet.

That play is very cost-sensitive and very reserve-sensitive, and so the rate of return as we see is starting out. On pre-drill basis it was a little bit lower than the rest of our opportunities. So we need to see enough encouragement to make us want to go out there and actually add that to our portfolio.

That’s kind of where we are at -- would like to see..

And what was the cost on that first well?.

Yes, I think including facilities, that was a little over $7 million..

Okay, great. And then on the new opportunities, just a couple points of clarification.

First, how closer are you to that target of 40,000 acres? And then second to confirm, are you the operator out there?.

We are -- I can't say a whole lot about that, Chad, but we are fairly close to that number. And we will share operations on that project with our partner..

We’ll probably operate the drilling and they will operate the production..

Okay. That’s helpful. Thanks. I’ll get back in queue..

Yeah..

(Operator Instructions) Our next question is from Michael Glick with Johnson Rice. Please go ahead..

Good morning.

Just in the Zavala/Dimmit county area, any thoughts to drilling an Eagle Ford well this year?.

Yes, Michael, we’re working on that now..

And then I guess -- compared to your previous, also I guess, it probably be a longer lateral bigger frac, is that fair?.

Definitely, longer lateral.

Carl, want to say?.

I think, you’ll see us do everything a little bit bigger..

Which is why Chesapeake has done and had fair amount of success with it, so..

Okay. And then in the BUDA, looks like that the Dunlap well is a bit further south compared to your existing wells.

I mean, is that thing successful? Do it derisk kind of the acreage in between Dunlap and the Beeler wells?.

Well, Michael, we like to think so but this is a statistical play. It’s fractured carbonate sections. We’re trying to learn as much as we can. We’re hopeful that that’s the case but we don’t know exactly. If -- even we have a very successful well there, that’s going to happen in between.

So we’d be very encouraged obviously if that well plays out in our favor..

And then in terms of the Stokes well and Madison/Grimes county.

What’s kind of the timeline look like there in terms of evaluating the cores and then going out and kicking out lateral?.

Well, I think the key there is industry consortium that we’re participating in where a lot technical data science is getting collected. Analog is integrated and we’ll have a better idea what the timing and the future looks like on that well..

That is probably several months..

Yeah. I think we always assumed from a budget perspective that it would be late in the year before we get back after there. And so late this year, early next year is not out of the question..

I mean, is it unreasonable to think that maybe next year you could have potentially three rigs in the area, one in Force, one in Chalktown and then other one on Iola/ Grimes spending on.

What you see there?.

Yeah. It’s considerable..

Got you. All right. Thank you very much..

Thanks Michael..

(Operator Instructions) It appears there are no further questions at this time. I'd like to turn the conference back to our speakers for any additional or closing remarks..

I’d just thank you for everybody participating today and we’ll look forward to updating you on our next call. That’s all we have. Thanks a lot..

And that concludes today’s conference. Thank you for your participation..