Good day. And welcome to the Contango Oil & Gas Company Third Quarter 2014 Results 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. I’d like to welcome everyone to Contango’s regular earnings call for the quarter ending September 30, 2014 this morning. I’d like to start by reminding everyone that the results for the three months and nine months periods ending September 30, 2014 reflect the merger with Crimson Exploration that was effective October 01, 2013. So 2013 results reflect -- or for the comparable periods in 2013 reflect 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 give a brief overview of financial results. Turn it over to Allan to give you a brief overview of the current operations and then we’ll follow that with the Q&A, and as we usually do, we’ll limit questions from the audience to those from analysts that follow our stock closely, as we believe that is most constructive and productive use of everyone’s time and especially in the case of today as we’re on a short fuse and present at Jefferies Conference right after this call. Before we begin, I want to remind everyone that the earnings press release and 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. Starting with review on financial results we reported net income of 3.7 million for the quarter or $0.19 per basic and diluted share compared to a net loss of…

Thanks Joe and good morning every one and thanks for being here today with us. I like to share few highlights about the information we provided in our operations release and where appropriate and meaningful, add few extra comments. First of all I’d like to say that when we do not have the definitive guidance, -- we don’t have any definitive guidance on our 2015 capital program as of yet, we’re probably a few weeks away from having that finalized and presenting that to our board. Given recent decline in oil prices and our view of staying within cash flow, our focus will most likely to be on further delineating our existing positions primarily Madisonville, South Texas and the three new plays that we’re got working now. And given our time constraints today, I’ll limit my comments to pretty high level for each area. In Madison and Grimes counties we concentrated our efforts this quarter on Chalktown portion of Woodbine play were we brought the Dean well online at a previously reported 30 day rate of 927 barrels equivalent per day and finalize the Heath well that so far has not lived up to expectations and we continue to test that. Despite seeing shows during the drilling phase in the Heath well, we really haven’t see anything by water thus far. We’ll continue to evaluate the well and learn from it. And we also three wells that are in process at the end of the quarter. We continue to be excited about Chalktown areas evidenced by our addition of second rig with the expectation that we will have two rigs operate in that area during 2015 utilizing the pad drilling approach. In Grimes County in order to release that we previously reported a notch well in the Tommie Carroll 2H…

Thank you. (Operator Instructions) and we’ll take our first question from Neal Dingmann with SunTrust.

Morning, guys. Allan, I know you haven't obviously put out official guidance, you did mention that for next year. But just your thoughts in broad terms how, between the Elm Hill, the FRAMS and the Cheyenne project, obviously a lot of upside there, how you'll balance that with obviously some of the existing Buda. I'm wondering more in broad terms, is it existing acreage, your core acreage? Would that be three-quarters of the budget versus quarter for some of these newer plays? Maybe if you and Joe can give a little color on that first.

We have a lot of drilling to do in the Chalktown area for next year I’ll tell you less so in the Buda down South Texas, we do plan to drilling some Eagle Ford wells down there, but it’s really our acreage position is set up, we do have the partner in our project in Fayette, Zavala county so we’ll have to work with them to figure what our plan is going forward given success there. But I would think that the majority of our budget would be directed towards Madison, Grimes some at Eagle Ford and then subject to success and some of these other plays that’s where the remainder of capital would go. We’re still trying to our belief especially in these lower commodity price environment, it’s just stay within cash flow with our budget. However, as given -- if we had an outstanding success at one of our three new projects that might change our view.

Exactly. And then was wondering about, in addition to the production guidance for fourth quarter you talked about the drilling related interference in three wells in the Buda play. Just your thoughts, is that going to be -- is that just limited to that area, or is that something you're potentially cautious on that's going to be more widespread? Or just maybe some more details around that.

I think I was just an isolating instance, but remember we’re not going to be drilling that much in Buda in 2015 it’s going to be more Eagle Ford.

No, good point. Okay, okay. And then I think I know this as far as, just going for the budget for next year, Joe, is it fair to say for now with your two positions out west in addition to obviously the Fayette position, just your thoughts as far as leases and expenses on that, would that be pretty minimal, at least for the start of the year?

In terms of new leasing?

Yes, sir.

Well, we will include in our 2015 budget a sizable number, similar to what we have in this year’s budget for the potential for new leases and new lease and new place in 2015 and our efforts to continue to build our inventory.

Okay.

As it relates to the existing plays that we already have it would probably being more affiliate kind of expenditures.

Okay, that gives that’s where we’re going, I saw that, that was out there but I was wondering just based on Allan’s comments I guess if that could change or that still the planning at this time that is still to have spending on those kind of new leases and Joe, is that fair?

That’s correct.

Okay and just lastly, location at the Elm Hill project, obviously there is activity around you all in the Fayette, a lot of it looks -- starting to look quite good. Your thoughts, Allan, of just how active you could get. Just specifically, I'm interested in that area. After this, is it dependent on how this first well looks and that will determine activity for the beginning of the year? Just your thoughts around that?

I think we’ve got – we’re going to drill these four well and we’ll test each one of those wells in subject over the result of those wells I think that’s going to be driver for our level of activity, I mean in the event we have a large amount of success and very pleased with the results I think that both us and our partner would be very anxious about hearing and get after it, but time will tell.

(Operator Instructions) And we’ll take our next question from Kyle Rhodes with RBC Capital Markets.

Just on the strategic front, how do you guys currently view the relative attractiveness of share repurchases to potential M&A opportunities out there? Do you guys start to see any capitulation in ask prices just yet?

Well, we haven’t seeing -- the things that we looked at thus far we haven’t seen anything that’s compelling enough to go run down, but that’s obviously something that we’re very aware of and keeping our eyes on the market to see what opportunities might present themselves. So yes, we’re very engaged on that front.

And Kyle I’ll add to that, we’re going down a parallel path there we think that our stock is undervalued and good investment so we’re allocating some capital with that but still keeping our eye on the bigger picture being continued building of inventory for a drilling program going forward.

Got it, makes sense. And then just any additional color you guys can provide on that Heath unit Chalktown well? Anything you saw in the drilling completion that has you concerned about the southern Chalktown Area? Maybe some more color around that?

Well you’re going to get is good news and bad news out there, we’re evaluating that still, we’re looking at the water, what type of water we’re making, load water versus formation water, with chlorides might be, so we’re doing some further investigation there. We’ll apply some more scientific work out there in the near term that signing up was positive term in that. But it is important well for us and it’s important for us to have a clear understanding of what actually going on there.

Got it. Thanks guys.

And our next question is from Chad Mabry with MLV & Company. Chad Mabry - MLV & Company: Thanks. I wanted to drill down on Q4 guidance a little if I could and maybe get an idea of the offshore versus onshore split there. To specifically looking at Eugene Island 11, just curious how that performing now that you have compression installed there?

First of all, I would say that Eugene Island 11 is performing and we’re expecting those compression, we had really good performance installing the compressor with about 21 days on shut-in time and the wells are back on now and performing as we generally expected I think we’re going to be very close through the third quarter to what we budgeted offshore for the year from our PDP production. Chad Mabry - MLV & Company: So, just normal decline after that?

Yes, just normal decline. Chad Mabry - MLV & Company: Okay, great. And then going back to Fayette County with the four wells there, just curious are you testing different formation, different concepts there is that going to be one kind of horizon that you’re testing with those four wells.

Yes, this is Tom Atkins. We’re testing a variety of different things, formations, completions, all that kind of stuff. We’re trying to get a good knowledge on the spread of our acreage and we’re doing different things. Chad Mabry - MLV & Company: That’s helpful. Thanks guys.

And our next question is from Michael Glick with Johnson & Rice. Michael Glick - Johnson & Rice: Good morning guys. Just a question on pad drilling I mean kind of what’s the process would transition into that and what’s the go for pad design that you’re targeting?

Carl Isaac, again. I think several things actually relative to pad drilling, we obviously get some capital efficiency to begin with we’re moving rigs on the same location in 12 hours versus moving from location to location in three or four days. So you can kind of start there is capital efficiencies that are created by pad drilling. But there is also technical efficiencies that have been pretty well documented in most resource plays, in terms of placing fracs on adequately spaced wells or down space wells or really any spacing you want to talk about at the same time prior bringing adjacent wells on production. So we anticipate that we’ll have some production efficiencies, some reservoir efficiencies, capital efficiencies, that all come to bear as we drill -- as we move to pad drilling. Pretty excited about it we’ve spend a lot of time to delineating our acreage on a well-by-well, location-by-location basis. So this gives us an operational opportunity to finally start realizing some of the capital in production efficiencies that we’ve watched others enjoy. Michael Glick - Johnson & Rice: So I guess that sounds like the plan going forward and if so, should we expect kind of some lumpiness in production?

Yes, I think both lumpiness and production, but also a bit in capital when we’re drilling wells at $2.5 million or $3 million each three consecutively, we don’t incur the $3 million to $3.5 million completion cost as rapidly. So, when we go back out and we complete three wells in row that’s going to create some capital spikes as well relative to that specific asset. So we’ll see both on the production and the capital side to some extent. Michael Glick - Johnson & Rice: And just real quick, thought process on any of the other formations in that Madison and Grimes County area?

Yes, we’ve always believed that there was a tremendous amount of opportunity and additional horizons and formations in Madison and Grimes County so we’re currently working a lot of that stuff. We’ve drilled pilot holes this year, took core in a couple of zones so we’re looking at that, there is a tremendous amount of activity all around Madison county, but I like to keep looking at Madison county itself, tremendous amount of activity and multiple horizons Buda, Georgetown or even in Glen Rose, Edwards so there is a tremendous amount of opportunity up and down the section in Madison and Grimes county. Michael Glick - Johnson & Rice: Okay, thank you very much.

And we’ll now take a question from Curtis Trimble with Brean Capital.

Thanks, good morning, everyone. Third quarter CapEx a little shy of what I expected. I'm guessing based on Carl's comments that had to do with, let's call it the lumpiness of completions. Can you give us any color on what fourth quarter CapEx might look like?

Well, the guidance that we’ve given for the year of 2.15 to 2.25, I think is still pretty good. So, fourth quarter would be an active quarter.

Good deal. And in terms of infrastructure around the plays in Wyoming, I'm going to hazard a guess that you've got plenty of legacy infrastructure, but are there any pressure considerations for new versus legacy production?

I’m not sure I understand the second part of the question, the first part of the question as far as maturity of infrastructure and what we call a North Cheyenne in the Weston county we’re between two large fields that actually have productions in the zone, were looking at their one of the zones and so there is some infrastructure there that’s just mature. In Natrona County, it’s not so much but we don’t really see that being a big problem at this point in time and I think that’s something that we’re getting our arms around right now and we’ll have a better feel for us as we progress through the project.

And you’re expecting that to be a dominant oil play?

Sure, hope so and thoroughly expect it will be.

Appreciated.

And this concludes today’s question-and-answer session. I’d like to turn the conference back to our speakers for any additional remarks.