Good morning. My name is Denise, and I’ll be your conference operator today. At this time, I would like to welcome everyone to the Second Quarter 2012 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions) Thank you Mr. David Welch, Chairman and CEO, you may begin your conference.

Okay. Thank you very much, Denise, and welcome everyone to our earnings conference call. Joining us this morning is Ken Beer, our Executive Vice President and Chief Financial Officer, and Ken is going to review the highlights of our financial results and then turn it back over to me for some commentary on our operational results and the progress in executing our strategy to invest in margin-advantaged natural gas basins and world-class oil basins. Then we’ll be happy to take your questions. So, with that, I’ll turn it to you, Ken.

Well, thank you, Dave. Let me go ahead and being with the forward-looking statement. In this conference call, we may make forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 34. These forward-looking statements are subject to all the risks, uncertainties normally incident to the exploration for and development, production and sales of oil and natural gas. We urge you to read our 2011 Annual Report on Form 10-K and most recent 10-Q for a discussion of the risks that could cause our actual results to differ materially from those in any forward-looking statements we may make today. In addition, in this call, we may refer to financial measures that may be deemed non-GAAP financial measures, as defined under the Exchange Act. Please refer to the press release we issued yesterday, which is posted on our website for a reconciliation of the differences between the financial measures, and the most directly comparable GAAP financial measures. And with that, I won’t go into all the financials in detail. I’ll focus on a few items. Starting off, earnings for the quarter were $30.5 million, or $0.62 per share, under the First Call estimate of $0.81, with some of the variants due to higher non-cash interest expense and non-cash DD&A expense. Our discretionary cash flow for the quarter was $147 million or right around $3 per share, which is pretty close to the First Call average of $3.06. Production for the quarter came in at 40,500 Boe per day or 243 MMcfe per day. This was at the lower end of our range for the second quarter guidance, primarily driven by greater than expected third party pipeline downtime and maintenance projects. Shut-ins due to tropical storm Debby, especially at Pompano where the Destin pipeline that…

Okay. Thank you, Ken for that comprehensive run through of our financials. We did continue our forward momentum through the second quarter, despite this fall in gas prices, third party pipeline shut in an early tropical storm of valuation and shut in and the Gulf, the tornados in Appalachia. We delivered our production at about 41,000 barrels of oil equivalents per day, which was within the guidance ranges but slightly below the mid-point, primarily due to the deferral that 2500 barrels equivalents per day from third party pipeline issues and tropical storm Debby, as Ken had elaborated on. We posted net income of 31 million, $0.62 a share and discretionary cash flow of 147 million, about $3 a share. It’s a pretty good quarter despite the headwinds on the production side and low natural gas prices. Our operations teams are delivering good results from our ongoing operations. And we are also closed on the acquisition of the remaining 25% working interest in Pompano in late June, after assuming operatorship in March. We have an exciting work program planned for Pompano over the next several years to deliver its value and have already increased gross production from the field from about 5000 to 6500 barrels of oil equivalents per day. The discoveries at Pyrenees, Wideberth and La Cantera are producing about as forecasted this year. In addition, we have extended the size of La Cantera successful stepout well. Production at our liquids rich Mary field in the Marcellus shale play continues to climb. And production from these fields is offsetting the decline in natural gas production we are managing in our legacy conventional Gulf Coast businesses. We are presently producing about 16% of our production from the Marcellus, 3% from deep gas and 32% from deep water. For the first time,…

(Operator Instructions) Your first question comes from Michael Greco with Johnson Rice. Your line is open. Michael Greco – Johnson Rice: Good morning.

Good morning. Michael Greco – Johnson Rice: Just in terms of your third quarter guidance, what kind of hurricane downtime is built into that?

Yeah, Michael its Ken. We haven’t given a specific number but it’s probably kind of a couple of Debbie’s. I mean it’s going to be a couple of smaller evacuations and shut in. It would not incorporate something like eight Katrina or a bigger hurricane. But we are just assuming there will be a little down time during the course of the third quarter. So we do have that at least baked in the guidance for the third quarter. We also had – after the second quarter – done some tinkering with the guidance. I mean our internal projections on downtime for third-party pipelines and maintenance which obviously, this past quarter, we were just off. We have at least tried to incorporate that learnings and have that in our third and fourth quarter guidance, as well. Michael Greco – Johnson Rice: Okay. And then at La Cantera number two I was just wondering if you could guys could provide some more color on that well. I know you talked about additional shells above and below the zone. I was just curious as to whether the kind of the shallower pay could be either a potential re-completion opportunity down the road or kind of the potential acceleration well.

I think it is a potential re-completion up the road. We are not exactly on the same page as the operator in terms of the size of the potential upside for those pays. But, they’re certainly could be – could be a re-completion potential, there. Michael Greco – Johnson Rice: Okay. And then just in terms of timing – I know the operator is talking about kind of a mid-September timeframe. You guys look like later in the fourth quarter, just kind of curious as to what the variables are, there, in terms of first production?

I think the variable really is just pipeline and issues in the area. The facility is built and so that’s not a real problem. It’s just a matter of getting the pipelines and getting them to a standard where they can flow at high rates. Michael Greco – Johnson Rice: Okay. That’s it for me. Thank you.

Thanks.

Your next question comes from the line of Brian Lively with Tudor, Pickering, Holt. Your line is open. Brian Lively – Tudor Pickering Holt: Good morning.

Hi, Brian. Brian Lively – Tudor Pickering Holt: Couple of follow-up questions on the Cantera. Remind me the drive mechanism is water drive correct?

Probably going to be a partial water drive, we’re not certain yet till we get some production and see what the pressures do as we start depleting it Brian. Brian Lively – Tudor Pickering Holt: Okay, so you haven’t seen depletion or you haven’t gotten the bottom low-pressure I guess at this point and the first well to know...

We just haven’t had enough withdrawal yet to really understand what it’s doing. Brian Lively – Tudor Pickering Holt: Understand. And what are you guys thinking at this point in terms of what may be the two P. or three P. – original gas in place our the actual recoverable resources from the overall prospect of what your drilled so far.

Yeah we really don’t put those numbers out, Ken. I don’t know if you have any commentary on it?

Again, we have tended not to have specific numbers per prospect. Certainly, this is very attractive prospect. And I think the second well certainly helps confirm some of the assumptions. But, it’s part of what we have in our reserves and reserve ads for the year. I mean so that hasn’t – we wouldn’t look to adjust that, right now. That’s a year-end exercise. Brian Lively – Tudor Pickering Holt: Okay. That’s fine. But maybe, then, how many wells, I guess, at this point, do you think you’re going to have to drill to adequately develop this play, considering the drive mechanism?

Yeah. We think probably two wells will be adequate. It may be potential later on; we learned something that requires a third well. But two feels about right to us at this point in time. Brian Lively – Tudor Pickering Holt: Okay. And then jumping over to Palmer, what’s going to be the plan, as you log this well? Are you going to log it then test it, are you going to log be suffice to figure out whether or not you’re going to proceed with development?

Yeah. It’s a little bit early days. But typically we would log the well. And if there’s something of interest, take some fluid samples and perhaps some sidewall course and we would hope that that would be sufficient. These are Miocene aged fans, which typically very high flow rate and unlikely that you would need a flow test on it. Brian Lively – Tudor Pickering Holt: Understand. Thanks for the comments.

You bet. Brian Lively – Tudor Pickering Holt: All right.

(Operator Instructions) Your next question comes from the line of Dave Kistler with Simmons & Company. Your line is open. Dave Kistler – Simmons & Company: Good morning, guys.

Good morning, Dave.

Good morning, Dave. Dave Kistler – Simmons & Company: With respect to Pompano, you mentioned the effective date and the pref right reducing the acquisition cost. Can you kind of break that down for us a little bit more? What was the effective date, kind of how much cash flow came through it and then how much was pulled out, as a result of another party exercising their preferential purchase right?

Dave, it was – I believe the effective date was July 1st of last year. And the closing date was June 18th of this year. The original price was 67 million. And we ended up paying 26. So, I’d say 90 plus percent of that was just due to cash flow generated during the time. But the pref right was a very small part of it. So, maybe even 95% of it is cash flow. Dave Kistler – Simmons & Company: Okay. And may be taking that step further, have you seen substantial declines in that production, or does it look like something a year from now that acquisition already pays for itself?

Hopefully later. It’s a pretty shallow decline field. And as you know, as I mentioned, we’ve been able to get production up about 1,500 barrels per day since March 1st. We probably have gotten most of the increase, already. There maybe a little bit more that we can get out of it before it starts on a fairly shallow decline. So, it should be in good form by next year. Dave Kistler – Simmons & Company: Great. And then looking at the Marcellus in your comments that costs are probably going to be down about $1 million per well as a result of new contracts, or the contracts that you put in place. Can you kind of remind us what current well cost are, and kind of time to drill and complete and where that’s headed over the last date as you guys have been more active, doing more pad drilling, et cetera?

Right. We started out a couple of years ago at about eight-point, something 8.5 million. We drop that down once we got into a pad drilling mode to about 6.3 to 6.5. And I would expect that this would get us about 5.3 to 5.5. During that process, we’ve also extended the length of the laterals by a significant amount. The higher – older higher numbers were when we were only drilling about 4000 foot laterals. Now we’re drilling laterals that are over about – that are over 5000 feet. So, in addition to the costs coming down, the actual productivity of the wells are coming up, which is a very good combination. Dave Kistler – Simmons & Company: And have you also witnessed, you know, time to drill and complete–?

The drilling time has come way down. I don’t remember specifically what the days to drill were. But originally, we were planning to drill 24 wells. We were thinking we are going to need a two-rig program and a rig and a half program, we’ve got all done with a single rig. So that’s just an indication of the speed right there. Dave Kistler – Simmons & Company: Okay. That’s helpful. And then, with respect to Parmer, pretty large range for the resourced potential there. Can you talk a little bit about why the deviation is so great and what that might mean as far as future of drilling additional wells there, et cetera, to produce that formation? And maybe how we should calibrate expectations of what we see on the first well?

Yeah, I wish I could give you some help, there, right now, David. But all I can really say is the Parmer well – we’ve got it in titled status for good commercial reasons. And as soon as we can put any info out, we would love to do that. But it’s going to be – you are just going to have to give us a little bit of time to answer anything about Parmer. We love the prospect. As you know, there were three – well into sidetracks that each averaged about 500 feet of oil pay. And those are kind of on the Eastern side. We moved over to the Western side of the block to see how big this thing might be. And it’s going to – it’s a complicated situation. And we’re going to need – we’re going to need a lot of data to figure out what it might mean. So please just – just bear with us a while. But one thing I’ll tell you is we’re certainly not giving up on Parmer. Dave Kistler – Simmons & Company: Okay. And then maybe lastly, looking at the production numbers you put out for July versus kind of your production guidance for third quarter and full year, it seems like July would be already on track to be at the midpoint of your guidance, and potentially, it looks like would be an additional La Cantera could be pretty conservative on the full year. I know you mentioned baking in some downtime for pipelines and for weather. But are those – the downtime that you’ve anticipated associated with that is that above normal expectations, just trying to calibrate as it looks pretty conservative, at this point.

I will let Ken weigh in on this. But I will just make a couple of comments. Number one, the third-party pipeline issues that we experienced in the Gulf in the second quarter were somewhat anomalous. But we’re starting to now think that the anomaly may be longer term, instead of just the one quarter blip. So we have built that in, as Ken mentioned into our future forecasts. We do have a moderate amount in there for hurricanes. But La Cantera thing, it’s just possible that it could come in early. But we are not counting on it to come in at the first part of the quarter or first part of next quarter, to have an impact. I don’t think we have much of anything baked in for the third quarter for La Cantera.

Zero.

In fact I’ve nothing.

Yeah and as Dave said, it is one where very difficult to anticipate when some of these – obviously by the definition these unplanned third-party pipeline downtime that you just – we don’t – we have got some history. Second quarter, just not being much greater than we thought. And then in the second quarter, you do tend to have the planned maintenance, because of weather. But looking ahead to the third and fourth we just baked in a little bit extra and as you point out, we do have some downtime for Hurricanes in there, just because we don’t know when that may or may not happen. And then, lastly, with La Cantera, once again, there is some dependency on a pipeline being – there’s a pipeline repair that needs to occur. And so we just – even though that’s scheduled to actually occur before the end of this quarter, since it’s out of our control, we just put some risk in the timing and we feel like that puts us more towards the midpoint of the quarter. Dave Kistler – Simmons & Company: Okay. And maybe last question on the pipeline side of things. With respect to La Cantera or other projects, is there a possibility to actually look toward workaround pipelines, especially given that you know, one pipeline associated with La Cantera that went down as a result of – just an operational issue or mishap. Have you looked at maybe having, I don’t know, an ancillary line that...

We actually were able to reroute the La Cantera number one around the pipeline that did have a rupture. Certainly from an infrastructure and gathering standpoint, we will continue to look at that. But in this case, we did have some redundancy. When we bring on La Cantera number two, the current avenue, you know, there will be some constraints. So that’s why we will need that first one to be repaired. But I don’t think it’s cost-effective to just lay too much redundant pipeline in the ground. But, we do have at least a number of spot in La Cantera is one of those cases where we have some different options. Maybe that we’ll look all little harder at and maybe had a possibly upgrade some of those options. Dave Kistler – Simmons & Company: Okay. I appreciate the additional color, guys. Thank you very much.

Thank you.

There are no further questions queued up at this time. I will turn the call back over to Mr. Welch.

Okay. Thank you very much everyone for attending the call. Despite these short term blips that were occurring because of weather and everything we feel the future is very good for the company. And we’re working hard to try to deliver value to those of you who have invested in us. So thanks for being on the call so long.

Thank you.

This concludes today’s conference call. You may now disconnect.