Callon Petroleum Co (CPE) 2013 Q3 法說會逐字稿

Good day ladies and gentlemen and welcome to the Callon Petroleum third-quarter 2013 earnings conference call. My name is Gwen and I will be your operator for today.

(Operator Instructions)

I would now like to turn the call over to your host today, Mr. Fred Callon, Chairman and Chief Executive Officer of Callon Petroleum. Please proceed.

Good afternoon and thank you for taking time to call in to our third quarter conference call. Before we begin, I would like to ask Joe Gatto, our Senior Vice President of Corporate Finance, to make a few comments.

Thanks Fred. At this point I would like to remind everyone that this conference call contains forward-looking statements which may include statements regarding our reserves as well as statements including the words believe, expect, plan, and words with similar meaning. These projections and statements reflect the current Company's current views respect to future events and financial performance. Actual results could differ materially from those projected as a result of certain factors. Some of these factors are discussed in our filings with the Securities and Exchange Commission, including our annual reports on Form 10-K available on our website or the SEC's website at www.sec.gov.

We may also discuss non-GAAP financial measures, such as discretionary cash flow, PV10 measure, and adjusted net income. Reconciliation and calculation schedules for such non-GAAP financial measures are available in our third quarter 2013 results news release and also in our filings with the SEC. I will now turn the call back over to Fred.

Thank you, Joe. Today's call is certainly a milestone event for the Company. A call that finds the Company in the final stages of its transformation to an onshore operator, focused exclusively on the Permian Basin. We closed on the sale of the majority of our Gulf of Mexico assets earlier this week as part of the divestiture that was announced last month. We also closed the sale of our Swan Lake deal in the Haynesville shale.

We have come a long way in the Permian Basin since November 2009 when we were producing 350 barrels of oil a day to today when we expect to be producing roughly 10 times that amount by year-end. In the past quarter alone we grew our Permian volumes by over 30% from the second quarter due to our strong well performance and increasing level of drilling and completion activity.

Our outlook for the Company is relatively straightforward. Continue to deliver production and reserve growth from our derisk asset base in the Southern and Central Midland Basin. Expand our inventory through continued delineation of emerging horizontal zones, our Northern Midland acreage and downspacing initiatives. Selectively pursue acquisitions to add core areas for efficient horizontal program development and aggressively pursue further improvements in our cost of capital as a pure play onshore company. We are in the midst of an exciting growth phase for the Company.

I will now turn the call over to Gary Newberry, Senior Vice President of Operations, for an update on our recent activities in the Permian Basin.

Thanks Fred and good afternoon. I will start off by saying how pleased our team is with the progress we continue to make in the Midland Basin. This progress extends beyond the well performance that I will talk about in a minute. Callon recently received the Bruno Hanson/Midland College Award for Environmental Excellence, which recognizes an environmental project, procedure or proposal that exceeds industry standards in the basin. We received this award for our teams who work within the city of Midland to address landowner concerns, while safely developing our asset base. This achievement speaks volumes for our status as a well respected operator in the Permian Basin.

I will now move to an operations update starting at the East Bloxom field. We have recently placed three long lateral Upper Wolfcamp B wells on production with strong early time results similar to the four Upper Wolfcamp B wells previously on production. We continue to see strong performance at this field which started last year with the 321H. The four Upper Wolfcamp B wells drilled and completed to date have averaged 24 hour IP rates of 1,031 barrels of oil equivalent per day, and 30 day rates of 600 barrels of oil equivalent per day.

Based on these production results which capture over 1 year of history, we recently increased our Upper Wolfcamp B type curve to 480,000 barrels of oil equivalent in the area and will continue to review this estimate based on our increased number of wells with well-established production histories. With the Upper Wolfcamp B derisked at East Bloxom we are focused on continuing to realize the cost efficiencies from our established infrastructure as well as expand our portfolio of drillable locations. I will point out some recent initiatives on that front.

During the third quarter, we completed our first Wolfcamp A well, the Neal 341H. The well encountered a mechanical issue with the frac plugs resulting in less than one-third of the well-being properly stimulated. Despite these issues, the well produced at a 24-hour peak rate of 302 barrels of oil equivalent per day and a 30 day rate of 178 barrels of oil equivalent per day. We remain encouraged with this formation and plan to drill our second Wolfcamp A well in the first quarter of 2014.

Also in 2014, we will be drilling our first well targeting the Lower Wolfcamp B shale at East Bloxom, similar to the concept that we have proven at our Taylor Draw field with production from both the Upper and Lower Wolfcamp B zones. Finally, we have started to plan our next round of pad development based on downspacing. This will allow us to place seven laterals across a section versus the six previously planned.

I would now turn to operations at the Taylor Draw field. We have drilled and completed five wells to date, with short laterals of approximately 5,000 feet based on leach configurations on the eastern side of the field. Four of these wells were completed in the Upper Wolfcamp B zone, two of which were completed in the third quarter. These two wells, the Weatherby 2H and 3H, produced an average peak 24-hour rate of 634 barrels of oil equivalent per day, which was 92% oil and an average 30 day rate of 354 barrels of oil equivalent per day. The fifth well, the Weatherby 1H was completed in the Lower Wolfcamp B shale, which produced at a peak rate of 755 barrels of oil equivalent per day or 86% oil and a peak 30 day rate of 455 barrels of oil equivalent per day.

As discussed previously, we believe the Wolfcamp B can effectively and efficiently be developed with two independent and distinct levels of horizontal wells based on micro seismic analysis in the field. We're in the process of completing a three well pad targeting the lower Wolfcamp B with laterals of over 8,200 feet in length on the western side of field. This pad is currently expected to come online in December. These two fields provide a solid base of potential production and reserve growth for the foreseeable future.

Importantly, we have established the infrastructure and water capacity to support efficient pad development and are also moving up the learning curve on the important issue of well interference during completion work. This will become an increasingly important issue for Permian operators as pad drilling becomes more prevalent. With enhanced horizontal operating experience gained over the last 1.5 years, along with increased understanding of multiple benches, a potential resource to be developed, we added our second horizontal rig in the third quarter.

The rig drilled its first well at our Garrison Draw field in Reagan County and is currently drilling a two well pad at our Carpe Diem field in Midland County. The Garrison Draw well was a 5,400 foot lateral and is currently flowing back with encouraging early results. The two Carpe Diem wells are planned to be completed in the first quarter of 2014. Overall we expect the coming months to be busy for the team in the Southern and Central Basin. The Company currently plans to bring six horizontal wells on production in the fourth quarter of 2013 including the Neal 323H and the 324H that are currently flowing back. We expect this pace of activity will continue into 2014 with our two horizontal rig programs.

I will move to a discussion of recent activity in the Northern Midland Basin and specifically more Borden County acreage. Our most recent vertical test, the Lacey Newton 2801, was completed as a single stage completion targeting the Mississippian chat formation. The well produced at a 24-hour peak rate of 326 barrels of oil equivalent per day which was 92% oil. We are encouraged with this recent result and plan to drill another vertical well in early 2014 to continue our delineation efforts for this zone. I will now turn the call over to Bob Weatherly, our Executive Vice President and CFO.

Thank you Gary. Our net loss for the quarter was $892,000 or $0.02 per diluted share. This figure included an unrealized loss on commodity derivatives of $3.1 million. Excluding this unrealized loss and the related income tax effect, adjusted net income was $1.1 million or $0.03 per diluted share.

Operating revenues for the 3 month ended September 30 included oil and natural gas sales of $30.8 million from average production of 4,370 barrels of equivalent per day. These results compare with oil and natural gas sales of $27.4 million from average production of 4,337 Boe per day during the comparable 2012 period. Crude oil revenues increased 12% to $27 million for the 3 months ending December 31, 2013 compared to revenues of $24.1 million for the same period in 2012. Contributing to the increase in crude oil revenue was a 10% increase in realized crude oil prices compounded by a 2% increase in production.

The average realized sale price increased to $105.11 per barrel during the third quarter of 2013 compared to $95.86 during the same period in 2012. The increase in production was primarily attributable to a 43,000 barrel increase in production from our Permian properties, partially offset by the sale of our deepwater Habanero field and normally expected declines in our Gulf of Mexico fields. Natural gas revenue of $3.8 million increased 13% during the 3 months ended September 30, 2013 as compared to natural gas revenue of $3.3 million for the same period of 2012.

The increase primarily relates to a 16% increase in the average price realized, partially offset by a 3% decrease in natural gas volumes. The decrease in production was largely offset by the 106 million cubic feet increase in natural gas production from our Permian properties. The decline in production was primarily attributable to the previously discussed sale of our Habanero properties and abandonment of our Mobile Bay 908 property, which was partially offset by an increase from our East Cam 257 field.

From a cost perspective, all of our line item expenses were in line with previously provided guidance. Our LOE for the quarter, which includes ad valorem taxes was $13.11 per Boe total company. For just our Permian operations our LOE was $11.21 per Boe, representing a 15% sequential decrease from the second quarter of 2013. General and administrative expenses net of amounts capitalized decreased $600,000 during the 3 months ended September 30 compared to the same period of 2012, and relates primarily to costs in 2012 for nonrecurring employee related problems, including early retirements and severance expense for which we have no similar costs in the current period.

Discretionary cash flow for the 3 months ended September 30, 2013 totaled $19.2 million and net cash flow provided by operating activities as defined by US GAAP was $15 million for the quarter. Our capital expenditures for the quarter were $44 million with 86% of these expenditures directed to drilling and completion operations. At September 30, our total liquidity position was $59 million based on availability under our credit facility and cash on hand.

We've recently completed a regularly scheduled redetermination of the borrowing base under the facility, which also factored in our recent Gulf of Mexico divestitures. Our current borrowing base stands at $83 million, pro forma for the sale of the Gulf of Mexico properties. And this assumes the repayment of 50% of the outstanding principal of our unsecured senior notes. To the extent the Company elects not to redeem the senior notes before December 20, 2013, the borrowing base would be reduced by an amount equal to 25% of the aggregate principal balance of the 2016 senior notes outstanding on December 20, 2013 in excess of $48 million.

I will now take a minute to discuss guidance for the full year 2013. We project the total company production rate for the full year to be 3,800 to 4,100 Boe per day with oil accounting for 65% of these volumes. These numbers include our latest estimates for the timing of the closing of both the remaining Gulf of Mexico asset sales and the Haynesville divestiture. We expect production from our Permian assets to be 2,200 to 2,400 Boe per day for the full-year, an approximate 40% increase over full year 2012 production in the Permian Basin based on 2013 midpoint.

Please refer to our guidance press release, which provides additional details regarding guidance for 2013. This guidance will also be posted on our website in the Investor Section. Now I will turn the call back to Fred for his final comments.

Thank you Bob. Again, we appreciate everyone taking the time to call in. And we will now open the call to questions.

(Operator Instructions)

Will Green, Stephens Inc.

I wonder if we could start in Borden with that vertical test that you guys talked about. Could you expand on what you learned with this test? Is there any -- is it a sweeter spot of the formation, or just any color around that would be great?

Well, this is Gary. You're familiar with our previous results. I won't get into those. Our goal was actually with this well, was to show that we had a significant resource to mine in this area, which we knew was there in the MIss, and whether or not we could actually effectively stimulate that well without getting into a lot of water. And frankly, that is exactly what we proved.

We got a good IP and it is making 10 barrels of water a day. So, I think we achieved pretty much our goal. We actually located this well with a large geophysical information. We have got 3-D seismic across the area, and we are utilizing the 3-D seismic actually to help us understand where the best chat porosity is across the basin. And now we have got to go show you and show ourselves that that interpretation is correct and we can build there with similar results. And that is what the purpose of that early well in 2014 will do.

Got you. And shifting to the land side. After the GOM sale, I assume you are looking to bulk up around existing acreage in the Permian. Can you talk about, are there many land deals out there to be had still in the core of the play? Is that something we should expect you to be looking at over the next handful of quarters?

This is Fred. I think the answer is, yes, we are looking at it, and certainly we would like to find additional acreage acquisition opportunities in and around the areas we are currently focused in, the counties. We think there are opportunities out there. They may not be large opportunities, but we do think there continue to be opportunities to add bolt-on opportunities.

As we mentioned before, we also continue to look at acquisition opportunities. Again, in our core area out here. As we said before, and I think everyone knows, there are certainly not large unleased acreage positions out here. But we do feel like there are opportunities where there is acreage out here that we can add and maybe through a series of these transactions materially add to our position out here.

Right. Thank you guys. I will let someone else get a try.

Jeb Bachmann, Howard Weil.

Just had a few questions looking at some of the result and notably in Taylor Draw, those Upper Wolfcamp B. Do those compare favorably to your expectations or in-line with expectations? Just a little more comments there if you could.

Hi Jeb, this is Gary again. We have done a fairly positive review of well results in and around us. And the results we are getting match up with about a 380 MBoe type curve for that area in Reagan County. And that is really what we are expecting, that is what we're seeing.

Okay, do you guys have any plans for next year to drill a Wolfcamp A test in Taylor Draw?

We're kicking that around right now. We have got a couple of slots that we can do that on and we may end up doing it. We are really watching closely all of the nearby industry activity. We are kind of in a unique spot and we kind of like it, the fact that we have got a lot of really good operators in and around us, doing a lot of work, proving up these different levels. So we just have to pay close attention to it and be a very quick follower when those things really start materializing.

Gary, have you guys drilled or are you doing any deep Wolfberry pads at this point?

The only place we are drilling Wolfberry, meaning the vertical wells that we will drill, would be in the Pecan Acres area, Jeb. And we just recently completed another Pecan Acres well that was deep, clear to the Barnett again, and it is currently flowing back and we will have it performing here shortly.

And are there any Spraberry tests for 2014? Any that you guys are scheduled at this point?

We are thinking about it, but we do not have it firmly on the schedule. And likely, we might even focus one up in our Central Midland basin, is where we are thinking about it, Jeb, but we do not have it firmly on the schedule at this point in time. A lot of good activity going on up in that area right now.

A couple more quick ones if I may. One, Bob, I think if I heard this correctly, you said the LOEs for the Permian were $11.21 per Boe for the quarter? Is that right?

For the Permian, yes.

Do think that is a decent number going forward for the Permian?

Sure. We always try to trim it back, but I think for planning purposes, that is probably a good number for right now to go forward.

And then last one, Fred, the chances of not repaying that 50%, do you guys handicap that at all?

I think there is, at this point, I think there is a very good chance that we will pay down 50%.

Okay, thanks guys.

Ryan Oatman, SunTrust Robinson Humphrey.

I do not want to lose sight of the broader story of your improving leverage and liquidity while you are focusing on the Central and Southern Midland Basin. That said, you do have a very big position up in the Northern Midland Basin, so I do want to understand this vertical test.

You guys provided that 24 hour rate over 300 barrels of oil equivalent per day. Can you provide any information on how the extended performance looks, maybe perhaps pressures et cetera, is that similar to what you have seen in a Wolfberry well, or do you expect that well to come off a little bit stronger? Any color you can provide on the extended performance of that test.

Ryan, we are really early in this test. It came on with that initial IP about 20 days ago. We're encouraged in the fact that it seems to be leveling out and has some pressure behind it, so being only 20 days into the test, we are still making today about 130 barrels a day, so it looks like it is going to hold in there nicely. So I cannot tell you much more than that. I can only tell you what I know today. So in another three months or four months I will know better.

But the encouraging thing is it looks like it has got some pressure to it. It looks like it has got some longer-term performance indications to it. And we are happy with the fact that we are not making hardly any water, which was really the drawback that we had when we drilled our Mississippian horizontal well. We got into some water and we just couldn't pump it off. So it is very encouraging.

I agree. Why is that? Why were you able to prevent this one from fracking into water versus the horizontals?

We just put -- a couple of things we changed. We actually use the linear gel on the first horizontal well and we used a slick water system on this one. And we used a much smaller stimulation. So we were very careful that we didn't grow up and that we did not grow down. And all the transient analysis suggests we got a good stimulation on the zone that we have open.

Great. And what about the well costs for this one? Or if that is not really applicable, do you think this is something that could be vertically developed, or do you think this is something that needs to be developed horizontally to be economic? And you are really just trying to prove, stay in zone, prove that you have got a producing zone here without the water and then eventually go back horizontally after it.

It is a little too early to tell, Ryan, but my initial thoughts are we've put a lot of science into this effort. After our initial stumble, we put a lot of science into this effort. And we need to prove up at least our current technical analysis of where the Mississippian porosity is best developed with our next well. And then we will know more about how we would go about developing this from either a vertical perspective, which would be a very low cost vertical development, or, as well as the potential for horizontal development. But it is just to early to tell today.

Got it. Correct me if I am wrong. Have you guys provided any sort of potential locations for this concept? Do you feel one way or the other about prospectivity of those locations either as they exist now or that number potentially moving higher? And I will leave it at that. Thank you.

No, we have not provided any potential locations for either a vertical play or a horizontal play because we are way too early in Borden County for thinking about how we would efficiently go forward with getting access to that resource.

Makes sense. Thank you.

Thank you.

Mike Kelly, Global Hunter Securities.

I was hoping to take a look at some of your assumptions in the Permian going forward. Last quarter you gave a 5,750 exit rate for 2014, just one, wanted to confirm if that is still the right number. And then just talk about how you get there in terms of assumptions, really just the completion count. If you could allocate it out over the next four or five quarters, I think that would be helpful. Thanks.

To give you some general guidelines on how we came up with that number, Mike, we just took our two horizontal rig concepts throughout the year drilling in and around the four areas of development that we currently have. And that is Carpe Diem, East Bloxom, Garrison Draw and Taylor Draw, focused primarily on our derisked areas of two levels into Wolfcamp B, at Southern Midland Basin, one level at Wolfcamp B in the Central Midland Basin, and one level of Wolfcamp A across our entire derisked acreage position. And carried that out through 2014, ran it out and said this is what it could be. That is about 15 wells per rig year, so about 30 wells is what that is.

We are in the process right now of further refining our 2014 plan, both capital and forecast, and we will have something more refined for you sometime first quarter of next year. That is generally how we built that out. The assumptions we gave on performance were really around a 480 MBoe type curve at East Bloxom and really about a 380 MBoe type curve at the other three areas.

Great. It is very helpful. In just kind of a general sense, as you are transitioning out to really a very fast-growing Permian pure play here, the balance of adding acreage, spending on an increase well count here and how that really meshes with liquidity. How do you guys see it in terms of liquidity situation, how that plays out in 2014 and maybe even a little bit beyond that? Are you amply prepared now, post this sale to come?

I think, this is Bob. As far as liquidity, I think we are looking very carefully, we're completing our budgeting, of course, for 2014. Some of which had, the timing had a little bit to do with exactly when we would complete our Gulf of Mexico sale, we completed it a little bit earlier than we thought we would.

And we are looking at, as we have seen, I think as I noted that our borrowing base grew, actually it grew about 10% from where it was, even taking out the impact of losing the reserves that we had in the Gulf of Mexico, primarily the oily reserves we had at Medusa. And we looked, with Gary's program that seems to be going very well, we look to continue to PDP reserves at a pretty good rate through 2014, which we believe will continue to drive that borrowing base up at a good pace, and we certainly are planning around cash flow, strong cash flow from operations next year, which obviously, with increasing production will be much better. And we also look for a borrowing base to be there, so we feel very good about our liquidity going into next year.

Thanks, Bob.

Chad Mabry, MLV and Company.

Curious to get your thoughts looking into next year on the Carpe Diem area and what your program is going to look like, what your targets are, specifically looking at some offset operators drilling some nice cline wells in the vicinity. I'm curious if you had looked at the potential for some cline wells up there next year.

Chad, this is Gary. Our focus initially here is going to be on the Middle Wolfcamp B, and with the two wells we are drilling right now we will get those completed early first quarter next year. We will move the rig away back to Bloxom and drill some wells, then we will come back and actually drill two additional wells. So we will be in and out of Carpe Diem focused on the Wolfcamp B, the Middle Wolfcamp well.

We are really encouraged with that simply because of some of the offset wells to the east of us. Some very good wells have been reported there and what is driving some of that is the lateral length, and we have got plenty of room there to drill long laterals, as well as the deeper area that we are in the basin. We are much deeper in the basin, so we have higher core pressures and we have good drive for the fluids to get to the well bore. So we are encouraged with that and that is what we are initially focused on.

We are also very aware of the Cline development going on as well as the lower Spraberry and Joe Mill development that's going on in that area. We are watching that all and we will be very flexible on how we move to another level once we see some additional emerging information coming of the other offset operators.

That is great. Just as a follow-up I'm just kind of curious what pre-drill expectations are for those first two wells with the 9,000 foot laterals if you could.

The Carpe Diem wells? They are actually, we actually finished one of them and it was only an 8,100 foot lateral, we cut it a little short, but the next one will be making it to 9,000 feet and we are about nearly ready to set intermediate, to go with the curve now.

But predrilled expectations are anywhere from 400 to 600 MBoe. We see some incredible results up in that area. So varied as they are, we think that the way we execute, the way we frac wells, the way we perform, and at least the performance of our wells compared to others around us, we should be in the upper end of that side.

Sounds good. Thanks guys.

Jeff Grampp, Northland Capital Markets.

Most of my questions have been asked, but at East Bloxom, the downspacing is obviously really positive there. I was curious what is the densest spacing you guys have results on to date, if you have actually drilled on that spacing yet and if not, what the plans are around actually testing that spacing going forward.

We have Jeff. Actually, the wells at Taylor Draw today are actually on about a 700 foot spacing distance now. And that is really what the seven wells per section gets you, is about 724 feet between wells, and since those Taylor Draw wells are a little, those Taylor Draw sections are skinny and long, we get a little closer whenever we push six wells into those sections. We have tested it a little already and we believe it will certainly work at East Bloxom.

Okay. In terms of, do you guys have plans for that, maybe at the tail end of this year or into next year, to execute upon that lateral spacing then?

We actually intend to actually lock this down at seven wells per section for now. And watch -- we pay a lot of attention to what is going on in the basin and frankly this concept is being tested by many. I think I am just going to wait and see what emerges as the standard development pattern from companies such as Diamondback and Pioneer and others that are putting a lot of effort into this.

Okay, fair enough. That is all I've got. Thanks guys.

Thank you.

(Operator Instructions)

Don Crist, Johnson Rice.

In looking at your presentation, the Borden County slide, the Lacey Newton looks like very favorable results compared to the SM wells that were drilled to the west of you. Was the Lacey Newton drilled in the same formation, or in the same part of the Mississippian as those SM wells were?

It was certainly drilled to the same formation, the Mississippian formation. We have, based on our 3-D seismic, we were focused on some very well developed porosity within our acreage position. We do not have 3-D over the SM acreage, so I cannot tell you how it compares favorably or unfavorably. And I know the SM wells, whether they are vertical or horizontal, I think they have had some exceptional results, and I think they have had other wells that didn't pay out very well. But at the end of the day, we're just pleased to say that we have proven that we have got a significant resource on our acreage position and we think our 3-D seismic interpretation supports further work.

Are you ready to give an inventory or tell us how many bright spots you see across your acreage right now?

No Sir. I want to prove the concept myself before I start touting it to others. (Laughter) Let me keep proving it. I feel really good about it today. And I might well feel even better about it at the end of the first quarter of 2014.

Okay. I agree. Everything else has been asked. Thanks, I will turn it back.

Ladies and gentlemen, that concludes our question-and-answer session.

Again we appreciate everyone taking the time to call in. In the meantime if you have any questions do not hesitate to give us a call. Thank you.

Ladies and gentlemen, thank you for your participation on today's conference. This concludes the presentation. You may now disconnect. Have a wonderful day.