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Stone Energy Corporation (NYSE:SGY)

Q2 2012 Earnings Call

August 2, 2012 11:00 AM ET

Executives

David Welch – Chairman and CEO

Ken Beer – EVP and CFO

Analysts

Michael Greco – Johnson Rice

Brian Lively – Tudor Pickering Holt

Dave Kistler – Simmons & Company

Operator

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.

David Welch

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.

Ken Beer

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 produces into was shut in for a few extra days, and even had some tornado interruptions in West Virginia in late June. Debby probably impacted us by about 5 million cubic feet a day for the quarter. A lot of the third-party pipeline downtime and maintenance was roughly 10 million cubic feet a day equivalence.

It is important to highlight that the lower than expected quarterly volumes does not reduce reserve figures or estimated recovery. It is simply a slight deferral of revenue due to third-party pipelines and weather.

For July, we were back up to about 42,500 barrels equivalents per day or around 255 million cubic feet equivalents per day. For the second quarter the production mix continue to have an attractive oil and liquids rating with about 46% oil and 7% NGLs. and 47% natural gas. We would expect a similar mix in the third quarter and then a slight shift towards gas in the fourth quarter as incremental volumes from Appalachia and La Cantera number one will become more gas oriented.

Our production guidance for the third quarter is 41,000 to 43,000 Boe per day or 245 to 256 million cubic feet per day. We have also narrowed our annual guidance to about 41,000 to 43,000 Boe and the same 245 to 260 equivalents per day. Really, to account for the second quarter actual that the math pull this down. So this second quarter math – I mean second quarter actual and some additional projected pipeline downtime.

The higher weighting towards oil and NGLs continues to bolster our overall price realization which was around $57 per Boe or $9.50 per Mcfe for the quarter. It includes a continued uplift in LLS versus WTI in oil prices which we continue to see – which we see continuing throughout 2012 and really into 2013.

Regarding our gas price, note that we are now separating NGLs from the gas volumes. So our gas price realization is expected to track just under Henry Hub by really, $0.05 to $0.10. This is more than offset by the relatively higher NGL pricing on a Btu basis although the overall NGL pricing has been under pressure for much of the year.

On the cost side, our LOE was about $51.5 million for the quarter, which is right in line at least with our estimates, although, the lower volumes pushed up the LOE per Boe. We will expect this figure to stay within the $51 million or $55 million range for the remaining two quarters and we will maintain our LOE guidance at the year for 195 million to 210 million which had been reduced from the original guidance of 200 million to 215 million.

The transportation process in gathering expense appears to be tracking within our guidance of $28 million as the last two quarters – incline slightly with increasing volumes. G&A before incentive cost expenses tracking at the upper end of our guidance and this does include incremental, non-cash accretion expense of about $1 million per quarter, which is tied to the latest shares – ahead of schedule.

Our DD&A per Boe or Mcfe for the quarter was around $23.50 or $3.91 per Mcfe. At the upper end of guidance this is always a difficult figure to estimate on a quarterly basis. But we would hope to remain within the guidance range that we had out there for the year. Also, as mentioned on our last call, our projected non-cash accretion expense should remain just over $8 million per quarter for 2012.

Also, as suggested last conference call, our reported interest expense will continue to be higher in 2012 versus 2011 for a few reasons. We’ve mentioned the higher debt level. Also, just a smaller percent of the interest expense is expected to be capitalized this year, it happened in second quarter as well. And therefore, higher amount will be recorded as interested expense versus capitalized.

And then lastly, and this is the biggest impact, really comes from the accounting treatment on the convertible notes. As we mentioned before, the – despite the face value, coupon rate of 1.75% for the $300 million convertible notes, the accounting regulations stipulate that at assumed theoretical market interest rate, in this case it was about 7.5%, must be applied when reporting the interest expense.

So, although it’s non-cash, it will have an ongoing impact when we report the interest expense line, and therefore reported earnings. We would expect the reported run rate for reported interest expense to be around $7.5 million to $8 million per quarter, this year, with about 3.5 million being non-cash tied to the convertible notes accretion.

On taxes, we would expect our 2012 overall tax rate to stay within the 35% to 37% range with a great majority of that being deferred. And then, as we mentioned last quarter, regarding the share count, the calculated fully diluted share count was the 48.3 million shares.

However, as we mentioned last quarter, it is about 1 million shares less than the actual shares outstanding, including the unvested restrict the share, due to the accounting rules that govern the unvested portion, other restricted shares. And as we mentioned, the better approach for your EPS – for calculating EPS in your models would be to use the higher outstanding shares, which is about 49.5 million shares, which you’ll see in our 10-Q. when that’s filed later on the next – early next week.

That will get you closer to the actual EPS shares. Our EPS, earnings per share. CapEx for the quarter was just over $200 million, which did include the $26 million spent on the Anadarko 25% interest in Pompano. The difference between the $67 million announced price tag on this deal and the $26 million actually paid was primarily due to the cash flow generation or generated between the effective date and the closing date, as well as the exercise of a preff right by our partner on block 29.

Total debt for the quarter came in at $808 million. But, again, this incorporates the extrapolated figure of $233 million of the convertible notes with a face value of 300. Again, the accounting standards, demand that you extrapolate and record the theoretical debt value.

This calculated to the $233 million on June 30th. But this figure will continue to accrete at a rate of about $3.5 million per quarter to get you to the 300 million face value by March of 2017. Again, this is the non-cash interest that we referenced earlier. We remain undrawn on our facility and exited the quarter with just over our $220 million in cash.

Finally, we have added a few oil gas swaps to our hedge position since the last conference call, including some $4 per MMBtu gas hedges in ‘14 and ‘15. The full schedule is included in the press release for your review. That should wrap it up for the financial comments and I’ll turn it back it over to you Dave.

David Welch

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, our new businesses are producing on par with our legacy conventional Gulf Coast assets.

Another highlight of the quarter, is that we have maintained a steady liquids volume percentage to average about 53% of the total production in the second quarter. We still expect to deliver our full-year production within our original guidance.

To sum it up, in the second quarter of 2012, we grew production year-on-year by about 4% and maintained relatively flat production with the first quarter. Lower commodities pricing and higher seasonal LOE in the spring and summer were couple of the main reasons net income was reduced by about 20 million to $31 million in the second quarter.

Our balance sheet remained strong we had no new financing in the second quarter other than the renewal of our, in May of our bank revolving line of credit which stands at $400 million with no outstanding borrowings.

We have also have about $200 million in cash on the balance sheet and feel we are in good shape to execute our three-year plan which is populated with exploration and development projects in each of our business areas.

Most of the opportunities in our plant are already identified and owned by Stone, so we just have to keep executing. I believe that we have the capital projects processes and most importantly the people that can continue to do this successfully.

Now let’s take a quick walk through each of our business areas. We allocate capital and manager our businesses as the conventional Gulf Coast, deep gas, deep water, onshore oil and Appalachia. In the conventional Gulf Coast where we are focused on workovers and oil development drilling only, we have completed drilling a small set of projects which will help us maintain our relatively stable Gulf Coast production and cash flow profile.

Our three-year plan in the areas also aimed almost exclusively that oil production and maintaining stable significant cash flows from our current operations. We also have quite a large natural gas prospect inventory available that natural gas prices increase significantly.

We front end loaded our conventional drilling program this year and have already drilled the eight wells planned for the year. We’re in the final stages of completion of the program, right now. And expect these wells to add about 2,000 barrels per day of oils equivalent next month and in the fourth quarter.

We are not trying to organically grow the conventional Gulf Coast businesses because we don’t believe the remaining drilling targets are large enough to justify taking exploration risk. However, it is still attractive for drilling in-field projects, which generally have a 50% to 90% plus probability of success.

In our somewhat liquids rich deep gas play on the Gulf Coast, we successfully expanded the La Cantera discovery by drilling a step out well. This field should be netting stone 14 to 18 MBoe per day of wet gas along with 250 to 350 barrels constant by the end of the year.

During the second quarter, we also obtain rights to two additional deep liquids rich gas prospects and the other two corners of the same geologic mini basin and two discoveries at South Erath and La Cantera.

These prospects will probably be drilled in 2013 as we see very good potential in the deep gas play, which contains an up liquids to make it economically viable even with low natural gas prices. We’re also the high bidder on two offshore deep gas block in the most recently sale and have a number of these deep liquids rich gas prospects offshore, as well as onshore.

Now, we’re talking about deep gas, let me update you on the ultra-deep Lighthouse Bayou well. As you may remember, we encountered the top of the objective section a couple thousand feet deeper than projected. And an additional protective liner needs to be set before drilling through the full section.

Operations were suspended, pending the running of this liner and the acquisition of a larger more capable rig. However, during the timeout given lower natural gas prices and a significantly increased cost and risk associated with having to drill deeper into a high-pressure regime, we have now decided not to participate in the deepening of the well, feeling it does not fit our strategy.

Turning to the deep water, the big events of the quarter were the closing of our acquisition of the 25% of Pompano from Anadarko and our success at the recent resale wherein we tied with Statoil for fifth place in the number of blocks one, and spudding of our -step out appraisal well at our Parmer prospect.

We closed – on the Parmer acquisition on June 18 and now own 100% working interest in the field. Of course, integration was not needed since we own the other 75% and already operate the asset.

Since the closing was near the end of June and had little impact in the second quarter, however, the new acquisition should add about 1,500 barrel equivalents per day to the third quarter.

We expect to be awarded the 24 blocks, deepwater blocks upon, which we were the high bidder at later this summer and also gained 75% to 100% working interest and 30 deepwater blocks with the original Pompano acquisition. So, in the last six months, we will have added over 50 deepwater blocks to our portfolio, which now stands at around 120 blocks comprising roughly 680,000 gross acres.

Our team has gotten off to a great start at Pompano by performing work to increase the production rate from the field by about 1,500 barrels a day, since we took over operations in March.

The other deepwater fields at Pyrenees and Wideberth are now part of our ongoing production base, now that we have multiple deepwater fields on production; we are also considering Amberjack at Mississippi Canyon 109, which is in over 1,000 feet of water which is part of our deepwater business.

So, these deepwater fields are now an important material part of our production profile for 2012 and beyond and consistent with our strategy, they are all clearly price advantaged. On the deepwater appraisal and exploration fronts, our drilling operations commenced in the second quarter at the large step-out appraisal well at the Parmer discovery.

We expect to have well results in the current quarter, and hope to be able to report them to you then. The will is in a tight hole status right now. And we may continue to stay that way for a while. So there isn’t a firm promise that we can update you next time, but obviously, we will as soon as competitive situations and considerations allow.

You may recall that we promoted our 15% over 50% interest in this well and retain the 35% working interest. The benefit of this is that it reduced our cost interests from 50% to 20% in the Parmer step-out well. We felt this was prudent risk management because of step-out well is located nearly 2 miles away from a three wells with log pay. We expect to have a 35% cost and working interest in the project going forward.

Our three-year plan includes exploratory drilling and some risk-weighted follow-up development dollars files for potential discoveries. We currently expect to drill one to three deepwater exploratory wells each year, starting next year with Phinisi.

And you may recall at our Phinisi prospect at Walker Ridge 719, which is a four-way geological structural closer located between the Jack and St. Malo discoveries, which are also full rate geologic closures. The exploration plan permit has been obtained. The well is now merely awaiting its slot on the rig schedule and is expected to commence drilling in the first half of next year.

We own 20% working interest in Phinisi, which is operated by ENI this is another high potential impact prospect that should get started within the next year. Similarly, the exploration permit for the Floyd prospect to Green Canyon 451 has been obtained by our partner Woodside. And this well could be spuded in 2013 or 2014. We own 16% interest in Floyd. And are on shared oil area there’s really nothing material to report at this time.

We still have our small non-operated 2000-acre Eagle Ford position, which is being developed. And we maintain our options in the Cane Creek, Niobrara and Alberta Bakken areas.

Finally turning to the Marcellus shale in Appalachia where we own about 80,000 net acres. We’re presently producing about 45 million cubic feet equivalent per day, which includes 1250 barrels of condensate and 1100 barrels of NGL’s per day. We still expect to drill about 24 wells this year with a one-rig program and our liquids rich Heather and Mary fields in West Virginia.

So we’re quite happy with our operational results and the equivalent realized pricing in our Marcellus wet gas area. The prices for services have also weakened with gas prices and we have recently renewed our fracing contract in Appalachia. Under the new contract, we expect to save about $1 million per well. This will, obviously, impact the already robust economic returns in our high liquids focus area.

In the aggregate, our strategy is continuing to work. The conventional Gulf Coast is providing with the strong cash flow to support our growth areas. Our longstanding focus on price advantaged basins is particularly helpful during this period of low natural gas prices.

And we’re also receiving about a $12 per barrel positive differential to WTI for essentially all of our oil production. We still expect that production will grow somewhere between 14% and 21% this year over last year. And that our CapEx will be broadly in line with cash flow.

So, with this, we’ll be happy to open the floor for questions. Denise?

Question-and-Answer Session

Operator

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

Michael Greco – Johnson Rice

Good morning.

David Welch

Good morning.

Michael Greco – Johnson Rice

Just in terms of your third quarter guidance, what kind of hurricane downtime is built into that?

Ken Beer

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.

David Welch

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?

David Welch

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.

David Welch

Thanks.

Operator

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.

David Welch

Hi, Brian.

Brian Lively – Tudor Pickering Holt

Couple of follow-up questions on the Cantera. Remind me the drive mechanism is water drive correct?

David Welch

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...

David Welch

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.

David Welch

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

Ken Beer

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?

David Welch

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?

David Welch

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.

David Welch

You bet.

Brian Lively – Tudor Pickering Holt

All right.

Operator

(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.

David Welch

Good morning, Dave.

Ken Beer

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?

David Welch

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?

David Welch

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?

David Welch

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–?

David Welch

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?

David Welch

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.

David Welch

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.

Ken Beer

Zero.

David Welch

In fact I’ve nothing.

Ken Beer

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...

Ken Beer

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.

David Welch

Thank you.

Operator

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

David 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.

David Welch

Thank you.

Operator

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

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