E. Joseph Grady – Senior Vice President and Chief Financial Officer Allan D. Keel – President and Chief Executive Officer A. Carl Isaac – Senior Vice President, Operations Thomas H. Atkins – Senior Vice President, Exploration.

Neal Dingmann – SunTrust Robinson Humphrey Kyle Rhodes – RBC Capital Markets, LLC Chad Mabry – MLV & Co. Michael A. Glick – Johnson & Rice Company L.L.C. Joshua Daniel Young – Young Capital Management, LLC.

Good day. And welcome to the Contango Oil & Gas Results for Second 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 sir..

Thank you, Erin. Welcome everybody, welcome to the Contango’s regular quarter earnings call for the quarter ending June 30, 2014. I want to remind everyone that the results for the three months and six month periods ending June 30, reflect the merger with Crimson Exploration as effective October 1, 2013.

While the 2013 results are pre merger standalone Contango. On the call today are myself Allan Keel, our President and CEO; Steve Mengle, our Senior VP of Engineering; Tom Atkins, our Senior VP of Exploration and Carl Isaac, our Senior VP of Operations. I’ll start with a brief overview of the financial results.

Turn it over to Allan for an overview of the current operations and then we’ll open it up for Q&A, with the whole group after that. As a reminder we do limit questions to those from analysts who follow our stock closely, as we believe that 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 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 circumstances, however, those statements are just estimates are not guarantees of future performance or results and therefore, should be considered in that context.

We report a net income of $4.6 million for the quarter or $0.24 per basic and diluted share, compared to net income of $11.4 million or $0.75 per basic share for the pre-merger quarter, last year.

Included in the current quarter results are total charges of $10.6million and exploration expenses, related to our previously announced unsuccessful Ship Shoal 255 well.

Exclusive of those charges, net income per share would have been approximately $0.65 per share, which is consistent with recurring estimates on the part of the analysts that cover our stock.

Adjusted EBITDAX as defined in our release and which excludes that exploration expense was $56.7 million for the current quarter, compared to $24.3 million for the prior year quarter.

Adjusted EBITDAX was also consistent with consensus estimates with a period-over-period improvement due primarily to addition of the Crimson results and to higher natural gas prices. The prior-year results also benefited from $10 million in proceeds from the key man life insurance policy.

Production for the current quarter was approximately 10.6 Bcfe, or $116 million equivalents per day, compared to just over $62 million per day, in the pre-merger prior year quarter. Production was within guidance for the quarter, despite initial production at South Timbalier 17 which was originally planned to commence June of 1, slipping into July.

Guidance of a $100 million to $110 million for the third quarter is lower than the second quarter, because of the planned July shut-in of our Dutch Mary Rose wells at Eugene Island for installation of compression.

Those wells which were producing at approximately 61 million a day, net to Contango prior to shut-in, were shut-in from July 10 through July 30 and are slowly being brought back to pre shut-in rates.

Total operating cost for the current quarter, including direct LOE, production taxes, transportation cost, interest and cash G&A were $1.94 per Mcfe, compared to $2.91 per Mcfe in the prior year quarter. That is better than guidance and consensus estimates.

Negatively impacting the prior year quarter was $6.1 million in work-over costs of Vermilion 170. Exclusive of which total cash operating costs per Mcfe would have been $1.84 per Mcfe. You probably noted that our guidance for direct LOE for the third quarter is higher than that reported for the second quarter.

And that estimated increase is attributable to an approximate equal amounts, estimated LOE new South Timbalier 17 filed that just came online, higher expense work-over cost, an incremental cost at Eugene Island 11 to operate the new compression facilities.

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

Thanks Joe. And good morning everyone and thanks for being with us this morning on the call. I’m going share few highlights about the information we provided in our operations release and then I’ll add maybe a few extra comments from there.

In Madison and Grimes County, we continue to experience good results from our drilling there in the Woodbine formation, as evidenced by the new wells brought on production and reported for the quarter in each of our three areas in the Madison Grimes counties.

We commenced production on three wells in our Force area, one in our Iola/Grimes area and one our Chalktown area. On average for the two-county area, we continue to meet or exceed our expected internal type curve.

We also continue to improve on our drilling and completion costs in the area and plan to have two to three rigs active in that area for the reminder of the year. In the Chalktown area, we also had two wells that are in process. Our Dean #1H well is in early stages of initial production and will be reported in our next operations update.

So early results so far are similar to the Barr #1 well, our most recent reported well at Chalktown area. The Heath Unit A #1H well in Chalktown is currently drilling in the lateral section. Again, we have approximately 18,500 net acres in the Madison and Grimes County area with multiple formations that are perspective.

So this area will continue to be very, very important and active for us going forward. In the Buda down in South Texas in Zavala and Dimmit counties, we also continue to delineate that acreage there.

We completed and commenced production on six wells at average on an initial 30 day rate of about 647 barrels equivalent per day, average oil out of that is about 70%. You can see from our release that we also placed two others on production recently and we’ll report those results in our next operations release.

You also can see from the results provided that this is an area that is more statistical in nature due to the extensive fracture network, but on average, we continue to meet or exceed type curve. We expect to have one rig to two rigs active here for the remainder of the year as we continue to delineate our acreage position there.

Moving over to East Texas, the James Lime, we started our program in the James Lime in the first quarter. We’re drilling two wells, the first of which we reported an initial 30 day IP rate of 832 barrels equivalent per day about 60% oil, and the second which we reported this quarter at 586 barrels equivalents per day or 75% oil.

We’re going continue to monitor the flow back and production results, from these wells for the next several months and then make a decision on whether to bring another rig in to accelerate development there.

As a lot of you know, we do have approximately – excuse me moving down into the TMS, as most of you know we have about 28,000 net acres in the TMS. Of course that area has been generating a lot of interest by other operators. And a lot of people ask us what are we going to do with our acreage and how we’re going to pursue that.

We believe that the drilling cost in the area still need to come down pretty dramatically. Completion practices need to be optimized, before the returns in the play are comparative with other projects that we have in our inventory.

Therefore, we are going continue to wait and see how this thing unfolds and then make a decision on whether or not we’re going to participate in that play. As we announced in our release, speaking about new plays that we’re looking at new ventures, we’ve entered into two new plays in new areas for us.

First, we entered into a ground floor 50-50 exploration agreement with a private company, under which we’ve acquired approximately 42,000 gross acres in south-central Texas, primarily in Fayette and Gonzales counties where we’ll target a number of formations. We expect to spot our first operated horizontal well in the next several weeks.

Subject to success there, we do plan on drilling several more wells during the remainder of this year. If successful, that project could yield in excess of 200 drilling locations, if you assume the 115-acre spacing. So we’re very excited about that and we’ll get started on that right away.

Also, in addition to the play here in Texas, we’ve acquired a right-to-drill and earn up to approximately 119,000 gross acres in Natrona County, Wyoming where we’ll target the Mowry shale and other formation through horizontal drilling. We expect to spud our first operated well in mid-October.

Given success in this area, we estimate that we could add up to about 1,200 gross locations to our portfolio from the Mowry alone based on 80-acre spacing.

This is an area on which we’ve done technical evaluation of prior vertical drilling in production results for Mowry and are excited about the potential applying new technologies to this area, as well. We do have other projects, new ventures that we’re working on.

That’s going to continue to be part of our strategy to try to grow the Company, build the Company, in addition to the areas that we talked about earlier at such as the Madison/Grimes, Buda and others. .

.

.

.

.

.

.

.

.

.

.

.

.

Well, I’m not sure of your question, Neal. It’s basically a same shale sequence that we’re going to be exploring on and we’ve had we’ve seen some from some vertical wells.

So it’s basically same type of process we used up in Madison County in the Woodbine, drilling these longer laterals with multi-stage fracs, and seeing if we can make that play work there in that sand shale sequence.:.

Okay. That’s what I was wondering. You’ll attack it the same. I didn’t know, like, you said.

So you will do kind of some multi-wells there or multi-stack wells there?.

Right..

Okay.

And then lastly, just on the other acreage that you picked up, how does that work as far as with the drill, the right to earn? I mean, again, how quickly or what kind of – if you could maybe give a little more color on the terms around that?.

Well, I won’t go into a lot of detail, but it’s basically a staged approach where we can do some testing, drill a well, take some cores, test it for a while, see how it flows and then we can go to the next phase if we so elect. So, it’s kind of staged approach and that way we can maximize our capital program there..

Very good. Thanks, guys..

Okay, thanks, Neal..

And we’ll go next to Kyle Rhodes with RBC..

Hi, guys. Sounds like you’re about halfway to your 40,000-acre target in south-central Texas there.

What’s the current leasing environment look like down there?.

I would say it’s very competitive and we’re making progress, but we feel got the core of our idea ramped up. And there may be some more leasing to be done. But I think we got the core of it covered and we can kind of monitor as we proceed with our drilling and our testing process..

Got it. Fair enough.

And then, moving over to the Gulf, do you guys have a current production rate you can share for the Dutch and Mary Rose wells? Just trying to figure out – get a sense of downtime assumptions that are baked into your 3Q guidance?.

As we mentioned, it was producing a little over 60 million a day when it went down and it was off for 20 days. It’s been brought back up. We’re bringing it back up slowly. We’re not all the way back where we were yet, but we’re getting there.

But, Carl, you have any other guidance that you can give on the timing?.

The gross rate is around 100 million a day right now, which would be roughly two-thirds of what it was producing prior to the shut in..

Okay..

Great. That’s helpful. Thanks, guys..

And we’ll go next to Chad Mabry with MLV & Company..

Yes. Thanks, guys. Good morning. I had a follow-up to the production question there on Dutch and Mary Rose. You’re down about 10% sequentially in Q2.

Do you expect an uplift from compression? Where do you think you can get that field to?.

Carl?.

Well, I think what you’ll see with the compression is more or less a flattening of the natural decline over time. I don’t know if there will be a significant amount of uplift relative to the gross rates that are already produced. You’ll see a little bit of uplift, but primarily you’ll see a change in the shape of the curve..

Okay. That’s helpful.

And then I guess jumping over to the new leasehold that you acquired in Q2, is the $9.4 million that you spent last quarter, is that essentially all to the new Texas – the Fayette/Gonzales acreage?.

No, it’s a combination of a number of things, but it is included in there..

Okay.

Can you give kind of an average cost on that Fayette/Gonzales?.

No, Chad, we’re still leasing out there and it’s a competitive situation or potentially competitive. So, we’re reluctant to give out that kind of information at this point..

Okay.

But it sounds like you’re going to operate that position and kind of maintain a 50% working interest there?.

Yes, we’ll operate the drilling and then our partner will likely operate the production..

Great. That’s all I had. Thanks..

Thanks, Chad..

And we’ll go next to Michael Glick with Johnson Rice..

Morning, guys. A question on the Madison and Grimes area.

Could you provide an update on current costs at Force and Chalktown?.

Carl, why don’t you handle that?.

Well, I think what you’ve seen is over the last 18 to 24 months we set some targets in terms of what we thought our capital expense would be on a well-by-well basis. And we’ve moved closer towards pad drilling and those areas and had the obvious benefit of not moving rigs around, but rather skidding them.

And I think we’re down on the pad drilling in 5 to 5.1 neighborhood apples to apples, 6,000 foot laterals, 24, 25 frac stages. So I think that’s going to continue to be our target is to be in that 5 to 5.5 range going forward. And I think for the year we budgeted 6. So….

Or 7..

Yes, 7. So we’re making our goals there and we continue to create efficiencies..

And do you guys have an updated thought on spacing in the area?.

In the Chalktown or in the Madison, Grimes area?.

Yes, just generally..

Yeah, we’re – I guess in the Force area we’re at about a 1,000 foot between the wells. We still believe that there’s some really good potential go to down space. We been busy doing other things, though, just trying to expand the field limits.

In Chalktown we’re doing basically the same thing, keeping those wells pretty far apart trying to extend, get the extent of the field kind of pulled together. But we probably will go smaller in Chalktown sometime soon..

Then just last one for me – jumping over to Wyoming – is that acreage on federal or state lands?.

It’s all the above. It’s fee, state and federal..

Okay, got it. Thank you very much..

All right, thanks a lot..

Thanks..

And we will go next to Josh Young with Young Capital..

Good morning guys..

Good morning..

Can you talk about how the wells, both in Madison/Grimes and then in the Buda, compared to your expectations prior to the quarter?.

I think it’s a mix. I think we have some just really, really strong wells, especially play in both areas, but like in the Buda down in South Texas, that is a statistical play because it is a naturally fractured area.

We’ve got wells the two newest wells that we haven’t released any information on, they are very, very solid wells, very pleased with those. But we’ll announce the results in the next release. But at the same time, we’ve had some wells that just haven’t performed that well and it is because they are not really tied into the fracture network.

But, like these, the better wells, those wells will pay off in two months. So you can afford a few wells that don’t work in that play. Back up in the Madison/Grimes County area, we think our acreage is very undervalued in the public market, given the other transactions in and around us.

But because our well results especially now in the Chalktown area are very solid, and so we’re very pleased in terms of how it – compares to what we originally thought we’re very pleased with kind of where we stand today..

And then can you, as a follow-up, can you talk about the prospectivity in general at the Buda acreage? Have you delineated a certain portion of it that’s prospective and a portion of it that’s not? Or how should we think about that?.

I’ll turn that over to Mr. Atkins..

Well, we’ve kind of gone north and south, and we’ve gone up dip and down dip and we see good results in all parts of that. As Allan said earlier, it’s still kind of a statistical play. It’s if you encounter the fracture network – that’s the most important thing geographically.

So we still think that there’s quite a few more wells to drill to push that..

Great. And then, how is the performance relative to, I guess, the type curve or your expectation in aggregate? So, obviously some wells have been very, very economic, and some have been less.

So, in aggregate, how is it comparing to expectations?.

In general, I guess there’s a couple of ways of looking at it. We have had a mixed result. Some have been exceptionally good and some have been lesser. In terms of the rate-of-return expectation, we’re making a very good rate of return, 100% or greater as a project.

So, obviously, the good wells pay out in 30 to 60 days and that’s carrying the project forward. I think in general from a type curve perspective, again, we’re probably underperforming the type curve in terms of EUR, but from a rate-of-return perspective, our costs are coming down, and the rates are still high and so we’re getting it pretty fast..

Great. Thank you very much..

Thanks, Josh..

And we’ll go back to Chad Mabry with MLV & Company..

Thanks. Just wanted to follow-up. Looking through the Q, it looks like you’re unhedged into 2015. Obviously, with that much debt, you have a bit more flexibility there to determine your own strategy.

Just curious what you’re looking for to add hedges next year? Any thoughts on your strategy there?.

Yes, Chad. We believe in hedging. We actually tried to put on additional hedges immediately prior to the July 4th holiday and for the rest of 2014 as well into 2015. And then we lost the market in a big way over the next three or four days after that holiday.

So, it’s still on our radar to do, but we think the economic news out there and the political tensions in the world today will give us another opportunity to do that in the near future.

Generally, our strategy or our philosophy is to hedge in the neighborhood of 50% of our forecasted PDP for a 12 to 18-month period, except for the summer and fall months in the offshore because of hurricane risk. And so, that’s what we’ll be looking for an opportunity to do in a near future for the remainder 2014 and into 2015..

Okay. Thanks..

And it appears there are no further questions in the queue at this time..

Okay. Thanks for everybody joining us today..

We look forward to seeing you on our next call at end of the third quarter..

And this does conclude today’s conference. We thank you for your participation..