Callon Petroleum Co (CPE) 2012 Q3 法說會逐字稿

Good afternoon. And welcome to the third quarter 2012 results conference call. All participants will be in listen-only mode.

(Operator Instructions).

After today's presentation, there will be an opportunity to ask questions.

(Operator Instructions).

Please note, this event is being recorded. I would now like to turn the conference over to Mr. Fred Callon, Chairman of the Board and CEO. Mr. Callon, please go ahead.

Thank you. Good morning and thank you for taking time to call in to our third quarter results conference call. Before we begin the formal portion of our presentation I'd like to ask Joe Gatto, our Senior Vice President Corporate Finance to make a few comments.

Thank you, Fred. We'd 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 of similar meaning. These projections and statements reflect the Company's current views with 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. Reconciliation and calculation schedules for such non-GAAP financial measures are available in our third quarter 2012 results news release and in our filings with the SEC. And can be referenced there on our website at www.callon.com for subsequent review. Fred, turn it back to you.

Thank you, Joe. We're pleased to report several key accomplishments in the Permian Basin that we believe will provide the foundation for production and reserve growth in the coming quarters. From an operational perspective, we reported strong results from our second Wolfcamp B horizontal well at the east Bloxom field at a rate of 780 barrels of oil equivalent a day on a 24 hour IP rate and 553 barrels of oil equivalent per day on a 30 day rate from first oil.

Together with our first well in the field, this drilling program has produced an average 30 day rate of approximately 575 barrels of oil equivalent per day and has largely derisked this acreage position. Combined with our Taylor Draw acreage, we've assembled an inventory of 34 horizontal drilling locations targeting the Wolfcamp B and 36 locations targeting the Wolfcamp A. These positions provide a solid base of opportunity to build on for the ongoing evaluation efforts on our properties in the Northern Midland Basin. To that point we are currently completing a horizontal Cline well in Borden County with a lateral length of 6,679 feet. This well will be an important data point in our continued technical analysis of this part of the basin and we expect to have production results by the first quarter of next year.

We're also in the process of drilling a horizontal Mississippian and lime well in the area, which has the potential to add another 25 locations to the 120 potential Cline locations on our 14,500 net acre position in Morgan County. Taking a step back from our recent well results, we've made substantial progress growing our acreage and production in the Permian Basin this year. Callon has grown its lease hold by over threefold in 2012 with the acquisition of a total of 23,200 net acres in the Midland Basin, including the acquisition of 7,000 net acres in the Northern Midland Basin at a cost for approximately $700 an acre since July 1. These acquisitions have increased our current position to over 32,500 net acres in the Midland Basin, targeting multiple vertical and horizontal oil plays.

We continue to evolve our drilling program in the basin since 2010 and view the horizontal development and a high graded vertical Wolf B program as the key drivers of efficient capital deployment within our portfolio. To that end we will evaluate three horizontal oil plays in 2012 and are also monitoring activity in new target zones in the basin, which could contribute to additional multi-zone potential on our existing properties in the future. We will remain focused on converting our growing inventory of horizontal locations to production and cash flow in 2013, building upon our current production of approximately 2100 barrels of oil equivalent per day.

I will now turn the call over to Gary Newberry, our Senior Vice President of Operations, for an operations update. Following Gary's comments, Bob Weatherly, our Executive Vice President and Chief Financial Officer, will discuss our financial results for the quarter and we will then open the call for Q&A. Now I'll turn the call over to Gary.

Thank you, Fred, and good morning -- good afternoon, I'm sorry. Good afternoon. We continue to progress on our horizontal development program focused on the Wolfcamp B and the Southern Midland Basin. As was reported last quarter, the Neal 321H well, our first horizontal well in our Bloxom Field in Upton County, was drilled to a lateral length of 7,430 feet and was completed with 27 fracture stimulation stages. The 321H had an initial 24 hour production rate of 774 barrels of oil and 319 Mcf of gas for a combined rate of 827 barrels of oil equivalent per day and an average 30 day production rate of 598 barrels oil equivalent per day.

The Neal 651H, our second horizontal well in Upton County, was drilled to a lateral length of 7,113 feet and was completed with 24 fracture stimulation stages. The Neal 651H had an initial 24 hour production rate of 720 barrels of oil and 359 Mcf of gas for a combined rate of 780 barrels of oil equivalent per day and an average 30 day production rate of 553 barrels of oil equivalent per day. We will return to Upton County in early 2013 to drill three wells from the same pad, one of which will target the Wolfcamp A horizon.

The Upton County acreage provides for an additional 22 Wolfcamp B wells and potential for 24 Wolfcamp A wells. Including the derisked Reagan County acreage added in July, the Southern Midland Basin provides for the drilling of a total of 36 Wolfcamp B wells and 36 Wolfcamp A wells. Our first Reagan County well will be spud later this month.

Moving to our Borden County acreage in the Northern Midland Basin. As mentioned last quarter, we drilled the Shirly Newton 4801 vertical well to 8,530 feet into the top of the Ellenburger formation. The Shirly Newton 4801 will be tested in the Ellenburger formation and pending those results recompleted into the Mississippian formation. We've also drilled the Vicki Newton 3801H, our first horizontal Cline well, to a lateral length of 6,769 feet. We fracture stimulated the well this past week and we are currently drilling out plugs. We should have indicative early production results mid to late December. Given this is one of the first horizontal Cline tests in the area, we do not plan to share any further information regarding this well until the first quarter of 2013, after we have had extended production results from the well.

We are currently drilling the Shirley Newton 2301H, our first horizontal Mississippian well. This well should be completed in December with early production results in late January. Callon's vertical drilling program is currently focused on its Pecan Acres Field in Midland County and CH Ranch Field in Glasscock County.

At Pecan Acres three wells were completed in the third quarter and are in the process of flowing back and two additional wells are awaiting completion. We're evaluating potential of deeper zones, completing one well to the depth of the Woodford interval and a second well in the deeper Atoka sands. At CH Ranch, one well targeting the Fusselman formation is awaiting completion during the fourth quarter of 2012. Since completing our Bloxom horizontal wells, net production from the Permian Basin has averaged 2,145 net barrels oil equivalent per day for the month of October.

Moving to our deepwater assets in the Gulf of Mexico. Habanero had 39 days of scheduled down time to accommodate construction activities on shelves, auger platform and an additional seven days of down time associated with Hurricane Isaac. Medusa experienced nine days of down time for Hurricane Isaac and Hurricane Isaac had minimal impact to shelf production. The Habanero number two side track targeting up-dip proved undeveloped reserves is scheduled to commence in late December or early January, with first production targeted for end of the first quarter 2013. Finally, in the Gulf of Mexico, natural gas production from our East Cam block 257 field remains shut-in due to a pipeline leak in the section of line upstream of East Cam 257. Production is now expected to be restored by the end of the first quarter of 2013.

Now turning to our quarterly comparisons. Our net production in the third quarter of 2012 averaged 4,337 barrels oil equivalent per day, which was comprised of 63% oil and 37% natural gas and NGLs. This compares to production in the second quarter of 2012 of 4,107 barrels oil equivalent per day. The variance in the third quarter of '12 is due to reduced down time at Medusa and increased production in the Permian Basin offset by scheduled down time at Habanero and down time associated with Hurricane Isaac.

Production in the third quarter of 2011 averaged 5,261 barrels oil equivalent per day, which was comprised of 56% oil and 44% natural gas and NGLs. The variance in the third quarter of 2012 is due to the scheduled down time at Habanero, along with normal and expected decline on the deepwater and shelf assets, down time related to Hurricane Isaac, down time on East Cam 257, all partially offset by growth in the Permian Basin. Production through the third quarter 2012 averaged 4,251 barrels oil equivalent per day, compared to 5,182 barrels oil equivalent per day through three quarters of 2011. The variance in 2012 is due to the scheduled down time at Medusa and Habanero, along with normal and expected decline in the deepwater and shelf assets, down time on East Cam 257, all partially offset by growth in the Permian Basin.

On the expense side, LOE including severance for the third quarter of 2012 was $5.9 million or $14.69 per Boe. LOE for the second quarter of 2012 was $5.8 million or $15.57 per Boe, essentially unchanged from quarter to quarter. LOE through three quarters of 2012 was $20.5 million or $17.50 per Boe, compared to LOE through three quarters of 2011 of $16.3 million or $11.54 per Boe. Higher LOE in 2012 was associated with the Haynesville remediation work and added wells in the Permian Basin. The LOE per Boe metric is further negatively impacted by reduced production, as explained earlier.

Turning now to our 2012 guidance. Our current estimate for 2012 capital expenditures remains unchanged at $152.5 million. Production guidance for 2012 remains unchanged and is expected to range between 4,350 to 4,650 net barrels oil equivalent per day. LOE including severance taxes guidance for the year remains unchanged and is expected to range between $27 million to $31 million for 2012.

In summary, we're encouraged with the results of our first horizontal wells in Upton County. Our current multi-year inventory of horizontal well locations targeting the Wolfcamp shale and the Southern part of the basin provides for significant value-added growth in the near-term. In addition, we look forward to reporting results from our Cline and Mississippian wells in the future. I will now turn the call over to Bob Weatherly, our Executive Vice President and CFO.

Thank you, Gary. I will now discuss the remaining third quarter 2012 results of operations as we reported in yesterday's earnings release. For the third quarter of 2012, the Company reported a net loss of $1.1 million or $0.03 per share. Excluding the aftertax losses related to mark-to-market derivative positions, net income was essentially breakeven for the quarter.

Operating revenues for the three months ended September 30, 2012 include oil and natural gas sales of $27.4 million from average production of 4,337 Boe per day. These results compare with oil and natural gas sales of $33 million from average production of 5,261 Boe per day during the comparable 2011 period. Two-thirds of the 18% decrease in oil and gas sales resulted from decreased production, which Gary has discussed. The remaining third of the decrease in revenue relates to pricing. Our oil price realizations exceeded NYMEX price by $3.64 per barrel in the third quarter of 2012 due to positive hedging impacts and the premium received on our offshore production partially offset by Permian Basin differentials and transportation costs.

Our natural gas price realizations on an MMBtu equivalent basis exceeded NYMEX prices by $0.86 per Mcf in the third quarter of 2012, primarily due to the value of the natural gas liquids and our Permian Basin and offshore natural gas streams. On a combined hydrocarbon equivalent basis, Callon received $68.67 per barrel of oil equivalent produced for the third quarter of 2012.

As we discussed in our 2011 10-K, the Company elected to no longer designate its derivative contracts as accounting hedges beginning with 2012 derivative contracts. Unrealized losses on mark-to-market derivative instruments net for the three months ended September 30, 2012, were $1.6 million, compared to none in 2011, when all derivative contracts were designated as hedges for accounting purposes.

We currently have approximate 1,670 barrels of oil per day hedged for the fourth quarter of 2012, with the weighted average ceiling and floor of approximately $92.50 and $123.50 respectively. For 2013 we have approximately 1300 barrels of oil per day hedged with the weighted average ceiling and floor of $90 and $116.

Regarding natural gas, we entered into a swap transaction in June for a volume of 3,000 MMBtu per day for the October 2012 to December 2013 term at an effective swap price of $3.52. We simultaneously entered into the sale of a put contract in calendar 2013 for 3,000 MMBtu per day at a price of $3. And the sale of a call option in 2014 for 1,250 MMBtu per day at a price of $4.75 per MMBtu. These option sales allowed us to increase the swap price received for the 15 month period starting in October 2012.

We will continue to monitor available hedging structures and have a target of hedging approximately 50% of our anticipated proven production on a 12 to 18 month forward-looking time frame. We may decide to increase this target in the future, as we continue to progress our horizontal drilling initiatives in the Permian Basin.

Depreciation, depletion and amortization, or DD&A, for the third quarter of 2012 decreased 8% to $12 million from $13 million in the third quarter of 2011. The overall decrease is primarily related to the 18% drop in total production in the third quarter of 2012 compared to the same quarter for 2011. On an equivalent basis, the DD&A rate increased to $29.99 per Boe from $26.88. Partially contributing to the increase per Boe is that prior period DD&A rates were effectively reduced by the impact of a 2008 impairment charge following a ceiling test write-down. This resulted in a lower prospective DD&A rate for the then existing reserves.

Subsequent increases in the rate are attributable to our planned exploration and development expenditures related to our on-shore reserve development, including the ongoing on-shore development cost increases in the Permian Basin. General and administrative expenses, net of amounts capitalized, were $6.4 million for the three months ended September 30, 2012, compared to $3.5 million for the same period 2011. $2.6 million of the $2.9 million period to period increase is related to the non-cash valuation adjustment required to adjust a portion of our non-dilutive cash sellable share based long-term incentive awards to fair value and not recurring additional employee related costs including some early retirement expense.

Interest expense on our debt obligations decreased 22% to $2.1 million for the three months ended September 30, 2012, compared to $2.7 million for the same period of 2011. The decrease relates to the redemption of $10 million of principal of our senior notes during June 2012, in addition to a $0.5 million increase in capitalized interest compared to 2011. Partially offsetting this interest expense was related to our bank borrowings. Please review our Earnings Release and 10-Q for further results of operations details for the third quarter 2012.

Now I'll take a minute to discuss guidance for the full year 2012, which remains unchanged from our previously issued full year guidance. As Gary mentioned earlier, we project daily production rate for the full year to be 4,350 to 4,650 Boe per day, with oil accounting for approximately 62% of the projected production for the full year. We are projecting general and administrative expenses to be in the range of $18 million to $20 million for the full year of 2012. Cash interest expense is forecast to be $12.5 million to $14 million for the year. For the full year 2012, the amortization of the deferred credit, which is recorded as a reduction to interest expense, will be approximately $2.5 million to $3 million. We are projecting a DD&A rate of $29 to $32 per Boe for the full year 2012.

Please refer to our guidance press release which provides additional details regarding guidance for the full year 2012. This guidance will also be posted on our website in the investor section. We are currently in the process of developing our 2013 capital budget. Our level of spending for 2013 will be dictated by several factors that we are currently evaluating. These include our ongoing evaluation drilling efforts in the Northern Midland Basin, the potential for development activity in the Medusa Field, year-end accounting reserve adds and the expected impact on our borrowing base and of course commodity price expectations. We currently plan to provide the details of our 2013 capital budget in January. Now I'll turn the call back to Fred for any final comments.

Thank you, Bob. With that I think we'll open the call to questions.

(Operator Instructions)

Susan Peng with Robert Baird.

First question is on rig count. Can you give us your current thoughts on how you would proceed to develop the Wolfcamp in the Southern Midland in east Bloxom going forward, like meaning how many rigs do you plan to run given the success of your first two wells so far?

Yes, Susan. As you know, we've got a firm commitment for one horizontal rig until April of 2014, and until we actually see what's going on with our Northern Midland Basin, the Cline and Miss wells, we won't make a firm commitment for a second rig. So it's still kind of in the planning.

If the Northern Midland Basin works the way we expect it to, we'll be looking at when we could bring a second rig in to work rigs in both areas and if for some reason it doesn't work, then we'll be using that rig down in the Southern part of the Midland Basin on the stuff that we know is fairly well derisked. So, that's about as firm a schedule as I think I can give you at this point in time.

And then the second thing, just kind of wanted to understand a bit more about the infrastructure in the Permian in terms of how you are currently transporting your -- getting your oil out to sales. Is it pipeline or trucking? And any issue with infrastructure?

Yes, Susan, that's a good question. Again, with the growth in the Permian, that's always been a bit of a challenge, but so far we haven't been restricted. We actually truck nearly all of our oil off of our facilities, either from Enterprise or Plains, and we use their firm capacity out of the basin to get it to market.

And we feel comfortable that they can manage our production, at least in the near-term, until we really start ramping up with good growth. The follow-on question, the infrastructure might be what is going on in the Northern Midland Basin, and I'll just go ahead and say that there is plenty of infrastructure up there for gas offtake, as well as oil offtake. Again, we will likely be hauling our oil and pipelining our gas, of course, but until we kind of see the prospective nature of that area, I don't see any real reason to think that we'll be restricted at all.

And then a third question. Regarding the acreage that you acquired, I thought the price was really good. So, I was just wondering if you are seeing more opportunities for similar acquisitions of acreage up there in Northern Midland.

Susan, it's Fred. We were very pleased with the acreage we were able to pick up. I will say that there are some additional opportunities, but I'll also say that since we really got started up there early this year, it's getting pretty leased up, up in that area. It is competitive, and I'd say it's rapidly getting leased up, and there are a few opportunities that we've got an eye on. So, I don't see us adding substantial new acreage, but I think we can add to our position.

Last question, just in terms of, because I know you guys are expecting meaningful reserve adds at year end, that should contribute to your volume base. I was just wondering when can we expect an announcement on your volume based redetermination.

SuLin, this is Bob. As you know, we just completed a re-do of our bank group and we just had a $20 million increase of the borrowing base up to $80 million. We anticipate that fairly soon after year end, once Gary has completed the reserves, we've had our third party engineer review those reserves, that we'll be bringing the banks in. So, we anticipate that will occur in the first quarter.

First quarter. Okay. Great. Thank you very much.

Mike Kelly with Global Hunter Securities.

Question's on the liquidity front. Hurricane down time hurt you guys in third quarter. You out spent your cash flow by a decent cliff. Now I've got the $36 million of liquidity left. I know you just touched on the borrowing base you hope to go up. But, what are your other options here? What's the strategy to really address liquidity at this point?

I would say that our -- we're in that process right now of determining what our CapEx will really be in 2013. As Gary said, the pace at which we'll drill and our cash burn for CapEx will depend a whole lot on what we finally do. Once we really get a better grip on what that is, once we fine-tune what production will be and once we kind of get through our borrowing base review in the first quarter, then we'll look at what options are attractive to us.

We certainly have said in the past that we flip the borrowing base and our bank, low cost bank borrowings to be a part of that, but there's several options out there, including the balance sheet options, and so we'll keep looking at them, Mike.

And on the production side, I know you're going to have formal guidance out there in January, but a lot of moving parts right now, Permian in terms of hooking up vertical wells, and obviously on the horizontal side, as well, the timing of those. You had a down time in the Gulf of Mexico. So, it is a lot of moving parts.

Was hoping maybe you could just kind of script it out for how we should think about production, not throughout the entire 2013, but just as we go from where we are today through the fourth quarter and Q1, Q2. Any help there would be greatly appreciated.

Let me see how I can balance this out. Let's start with where I think I'm at today, for the month of October. It's not in our release, but the month of October we produced right at 4860 barrels a day. Okay. That's kind of an up month for what we've had here recently. That's a starting point.

End of the first quarter, we've got a significant impact in the Gulf of Mexico because of the Habanero well. We're redrilling that well up-dip. I think we've told you before that that should be a net rate to Callon somewhere around 900 barrels a day. We also have East Cam 257 that's been off all year, essentially. That's all gas, but net to Callon it's 300 net barrels a day, and that schedule is getting more and more firm as to when that will come on. That will come on at the end of the first quarter.

We certainly have high hopes for our Cline well that we're now drilling out. We'll have another Mississippian well producing at that time. We'll be moving down to Taylor Draw to drill what I believe is still a very derisked horizontal Wolfcamp B well in the -- later this month. So, that will be coming on early first quarter.

So, I think you'll see good growth in the Permian. You'll still see decline in the shelf, except for when East Cam 257 comes on. You'll see a significant impact at Habanero, and then just minor decline at Medusa, because the Medusa redevelopment program has really been pushed back late into the year. If that helps you at all.

Yes. If you could peg maybe a sequential growth rate, I know it's going to be lumpy, out of the Permian, what's a good way to think of that?

I would say at the pace that we're drilling, Mike, we would probably be bringing on a horizontal well about on average one well every 35 days or so. So, if that helps you kind of plan that out with a one rig program. Again, depending how all this works out. If we've got really good results in the north and bring on our second rig late in -- or second half of '13 then that all changes. But, I'd say a well every 35 days or so is what we ought to be thinking about, if that helps.

On the Mississippian, your offset operator SM has had some real nice assessed there. Wonder if you could talk about what the read-through is for you guys. I know you're going to sit on your first initial Cline well there, but are we going to get some intel from you on what you see out of that first Mississippian, what you should have done in late January?

By the time we get to the point of talking about the miss we'll likely be talking about the Cline at the same time. So, we see what SM's doing just to the west of us. We're encouraged with those results that have been reported. We have now TDed our well and we're running casing on it today. So, that's why I'm confident we're moving to Taylor Draw next. We have a nice horizontal section here, and we'll complete it very similarly to the way SM has completed theirs. So, we hope to at least be able to report to you comparable results.

Great.

I would expect we'll be talking about the Cline in total toward the end of January or mid first quarter.

Real quick. What's the cost of that Habanero side track?

The Habanero side track is a total of $130 million gross. We have 11.25%.

Okay. Great.

We funded some of that in 2011 with a long lead item AFE to get ready for the well and we're funding the rest of it last half of this quarter and early part of the first quarter.

Okay. Thank you.

You're welcome.

Richard Tullis with Capital One Southcoast.

Gary, going back to Habanero, I didn't catch what the current production is in October.

I'm sorry, Habanero for October was right around 450 barrels a day.

And then the side track will add 900 roughly to that net?

That's correct. Right now the number two well is shut in, Richard. So, it's been shut in since, I think, June or July because of sub-surface safety valve. We're actually plugging the bottom part of that well in the next couple weeks to get ready from the up-dip redrill.

What I've just told you is producing from the Number 1 well, and it is producing fairly steady. That's a net number to us. So, it's pretty good well and then the Number 2 well will come on at the end of the first quarter.

Will that add -- there will be more than 450 plus the 900 plus you're getting the Number 2 well back.

No, no, no, the Number 2 well is actually the well we're actually side tracking. It will be the well that will come on new, with a new rate.

What's the exact timing of the maintenance down time and bringing on the, I guess, the other unrelated project into the facility?

Yes, for 2013, Richard, what we've been advised by the operators, and remember we gave you a good schedule in 2012 when that shift shifted, because we've had a lot of noise in our 2012 production because of the variable timing of all this down time related to these same issues. But what we've been told is that Medusa will be down the whole month of February for 28 days, and that's associated not with the Medusa asset. That's really associated, again, with further modification and maintenance associated with the west Delta 143 pipeline system that's owned and operated by Shell, but we just won't have an outlet for our production so we'll be shut in while they're doing some minor modifications on that.

And the modification's fairly straightforward. They're abandoning a facility right now that that pipeline used to terminate on and are just moving the termination point and the tie-in point to another line to another facility. They did the prep work in 2012. They'll finish it up in 2013. Habanero, again associated with modifications at auger in 2013, is scheduled to happen in the third quarter. It's really July, August and September and it's 74 days total. And remember what that's for is Shell has a very nice discovery called Cardamom coming across that facility that they're getting prepared to do, and so we'll just have to be down while they're making all those construction modifications over that time period.

Okay.

And Richard, I'll just point out one more thing. I'm sure you realize this but both of those are very significant to us next year because we know Medusa's a significant asset to be off for a month and then once the new well of Habanero comes back on in late first quarter, that whole facility will be down for 74 days in the third quarter. Those are very impactful in 2013.

I know you touched on the Cline well a bit. What are you looking for from that Mississippi lime well, as far as initial rate and cost?

Well, it's all we've paid attention to is what SM Energy's been telling us. We would love to be able to report the same type of thing. I've got their latest release right here in front of me. On average for three wells that they've reported, they've had a seven day IP rate of 604 barrels equivalent per day and 30 day rate of 540 barrels oil equivalent per day.

They're targeting $6.5 million a well. We'll probably be above that in our first well. I can see how we can probably get there. But we would love to be able to say the same thing they're doing. We think we've got it figured out like they have as far as what's producible and what's not, where the porosity exits and where it doesn't. Only time will tell. This is a bit of a step out for us.

And what did you say Medusa was producing in October?

It's right at 1400 barrels equivalent per day net.

Okay. That's all I have. Thanks a bunch.

You're welcome.

Ron Mills with Johnson Rice.

Question for you on the 7,000 acres that you added up in the Northern Midland Basin. I notice the location wasn't identified. Just curious if it's adjacent to or a step out from or something, if you're chasing something different than your existing Borden County acreage?

Yes, Ron, it's an extension of the play. It's not adjacent to it, but it's primarily in Lynn County.

And then, Gary, you walked through at the very beginning, and I apologize, I missed some of the details. But if you look at your potential drilling inventory down in the Southern Midland Basin, I think you said that you had 70 potential horizontal locations, 34 in the B and 36 in the A. Is that combined for both your Upton County and Reagan County projects?

That's correct, Ron. That's both of those projects we haven't added any inventory for Carpe Diem yet. We know there's a pretty good result out there close to Carpe Diem that was announced by Diamondback. That's where we have it in Reagan County and Bloxom County, or Upton County and Reagan County is where we would focus our initial development activities for the derisked area.

And then I know -- I don't know if it was at our conference or just in your prior conference calls, you also had some activity offsetting Kayleigh in the area. Has there been any intel from the drilling near the Kayleigh acreage?

I haven't heard a thing about that Devon activity, Ron. If you all know anything about it, just give me a call, fill me in. But I haven't heard a thing, so we haven't added any inventory there. The best news we've had recently is the well that RSP drilled that was in the Diamondback database, and that looks like a pretty good area, and it's just north and east of our Carpe Diem area. And so if that holds in there like it looks like it might, that could add an additional 18 wells in the Wolfcamp B.

And then you broke down the Wolfcamp A and B. If you looked at 2013, are you going to be more focused on Wolfcamp B drilling, or do you think it could be evenly split between the two, or is that still to be decided?

I want to get an early test of the Wolfcamp A, which is why when we go back to Upton County and drill actually off of our first pad drilling, when we drill three wells back to back to back with this nice Cassius rig. We'll want to get an early test of the A. Once we get that test, Ron, we'll drill it up as efficiently as we can driven by what we can add the best value to.

And then I can't remember who was asking the question about the rigs. It sounds like if North Midland Basin works you could have kind of a two rig program at some point next year. Based on the inventory and your internal capacity, is a two rig program about as much as you would like to and/or be able to run in the Permian?

It would certainly be something I would try to achieve by the end of next year. We have capacity in the organization to do more, but it all depends on just how fast we can run with liquidity beyond 2013.

And in addition to liquidity, is there any other constraints on you whether it's vendor constraints, I think SuLin you had to address on the infrastructure side? Or is liquidity as you look out longer term the primary constraint, and not any of the human capital infrastructure, et cetera?

I don't see any constraints from a human capital perspective. I don't see any constraints from a service provider perspective, Ron. We've got service providers now calling us saying that they can do the work cheaper and more efficiently, so we're happy with the environment we're in.

We think we're going to be able to drive some cost out of the equation here in the next month or so with some fairly rigorous review of the opportunities out there before us. So, it really comes down to success, reserve adds, borrowing base growth and getting our costs down to a very efficient manufacturing level. I think it comes down to just that.

Great.

Going in, echoing what Gary said, I think the timing, as Gary said will -- first quarter we'll be evaluating our Borden County and it really would be kind of at the earliest sort of mid-year if we wanted to add a second rig.

I think the combination of the production growth we're seeing and the borrowing base as we've seen this year, we've had two increases in the borrowing base and the borrowing base is almost double this year. And so we're seeing really good impact on the borrowing base from the expanding -- the credit facility earlier this year and the growing borrowing base.

We think cash flow plus that growing borrowing base will certainly allow us to continue growth through next year and then hopefully by first, second quarter we'll evaluate what's going on in the north and be in a position to make a decision about adding the second rig.

All right. Great. Thank you guys.

Will Green with Stephens.

So, before you guys added acreage up in the Northern Midland Basin you guys did a pretty extensive seismic shoot. Can you maybe remind us how the Cline looked versus the Miss and then talk about what differences you've seen or what differences you're seeing. Are you getting confirmation of that or those differences as you're drilling these first two wells up there?

Will, just to kind of set -- step back a little bit further. We kind of did a lot of petro physical work before we got the acreage. We did a lot of correlation associated with what might work in the Cline and the way it's working in Glasscock County. We felt really good about the way we had mapped a lot of information from vertical well points. We did a lot of core analysis, at least cuttings analysis, and a lot of log analysis and evaluation, porosity, permeability, oil in place targets.

That's how we kind of got focused on where we are now in Borden County. We think we've got a really nice sweet spot there that ought to work just as well or better than what's going on in Glasscock County. It's thicker. It's got higher oil in place target. It's got higher porosity. All the core that we did while we drilled the first vertical well validates all the things we thought so far.

We just need to correlate all that with a real production test to get comfortable about what the real potential could be in Borden County. And once we got the acreage, we then went out, we had some seismic over part of it. We went out and got 3D seismic over the rest of it, and all that seismic confirms for us, Will, is that the Cline is very regional. It extends across the entire acreage position.

It's rather -- if it works where we're at now, it ought to work across the entire position. Our view of what makes the Mississippian work is really porosity at the top, porosity development at the top of the Mississippian. And we think we've got that kind of figured out by utilizing our 3D seismic, and we would suggest that the Miss should be prospective over a third of the acreage position in what we see today.

Got you. I appreciate that color. And then can we jump over to the Neal wells. Talk about completion differences. I know the first two fairly similar initial rates, seems like one had maybe two or three stages, seems like one may have been gel versus slick water. I know there's some varying techniques in the basin. What are you guys seeing?

Is it -- are the curves kind of looking similar so far, excluding kind of what you saw on variance on the rate? What's the cost difference? Anything discernable you can tell at this point? And what's kind of the recipe that you -- I mean, I know it's hard because there's only been two tests, but what's the recipe that seems to make the most sense, based on any factor or any number of factors?

Yes, Will, that's a good question. In fact, we have a meeting next week here in this office with my entire technical team to review every bit of information that we have about those two wells. So, I would be a little premature to tell you the answer, because I don't know what all their views are, but I can tell you generally how they differ.

The 32,1 which was the first well, which had the higher IP, was the longer lateral and was fracture-stimulated with slick water and about 200,000 pounds of sand per stage, kind of the EOG model we were following. The second well, the 651, which was slightly lower in IP and slightly lower in 30-day rate but still a good performer, was 300 feet shorter in lateral length, only because we moved the location a little bit further north.

There wasn't any drilling problems associated with it, but we fracture-stimulated it with a gelled system, a linear gel system and increased the sand per stage to about 300,000 pounds per stage. So it was only fewer stages because it was a little bit shorter lateral, so the main difference was slick water versus a gel, linear gel system. And that was really what we considered, internally we call it the Pioneer model. Okay?

Because we considered both of those companies doing quite well in this play and we were trying to come in at the top of the learning curve and see if there were any material differences in the way those two different types of stimulations would work in our area so that we could apply what we felt to be the best practice across the area from day one. The linear gel frac is a little more expensive.

So, there's not enough material difference between the two wells for me to suggest that we ought to go do gelled system fracs. So, I would use slick water. That's Gary Newberry talking without all the input from my team, but if that helps you quantify at least the few differences that we saw at the time.

Got you. So, on kind of a decline curve not really a meaningful difference, but definitely the fact that you're having to pump more sand and the gel's a little bit more expensive. On a return standpoint that's going to be the better one, since they pretty much look, I won't say identical because they had a little bit different rate, but pretty close, right?

Yes. In general, I'll tell you that I would never expect the same result even from well to well. I think you're going to see variability. I think you see it across the base. I think you see it across the same lease. But in total, both of these wells, I think, are fitting our type curve pretty well of about 450 MBoe wells. I feel pretty good about both.

But because of the cost, I would lean toward slick water, and even with slick water we can still get the sand quantities up as high as we could with gel. So, I would lean toward the lower cost option, because I don't see enough of a difference in overall early time performance to justify the higher cost.

Can you remind me, just on -- further down the road, obviously, there's science in both of these wells, what do you think a typical cost difference would be between just that simple tweak?

That could cost up to about $400,000.

Got you. Okay. Guys, I really appreciate all the color. Thanks again.

Sure.

Ryan Oatman with SunTrust.

Wanted to talk a little bit more about the acreage position. I know you guys have tried to provide detail there. Can you just kind of walk us through the net acreage by county and then kind of after that more housekeeping item, walk through how you came to the acreage in Lynn County and any differences you're seeing in seismic, et cetera, Lynn versus Borden at this point.

Well, I guess a couple things. First, the seismic. We do not have seismic yet over this acreage, certainly new acreage. We do have seismic over the 14,000, 15,000 acres we acquired earlier where we're drilling the Cline and the Mississippian.

We mentioned, I guess, going back a year ago, we've done extensive mapping in the Northern part of the basin here, and it's really based on that mapping that we decided to pick up additional acreage in the Northern part of the basin. I would just say that what we're doing there in Northern Borden, obviously we feel like that moving into Lynn we think there are areas there that are also prospective, as we saw the opportunities there in Northern Borden.

Okay. That makes sense.

Ryan, you asked about the net breakdown.

Yes, I was curious how it broke down between all the different counties.

I'm going to give you some round-about numbers, but I'm going to be awful close here, okay. In Upton County where we drilled our first two wells, we're right around 3600 net. And Reagan County, where we're going to go next with the rig, we're right around 2000 net. So Southern Midland Basin around 5600 net acres. Again, a total of --. Once again, I'm talking prospective for horizontal drilling as we see it today.

We have additional acreage in the south that's all vertical development. I'm focusing on what we're currently targeting. That's why I'm -- if you look at our investor presentation it breaks it down by area that includes all of the vertical development that we've done also. So, I'm trying to focus you on what we're very much prospectively targeting now.

So, 3600 in the Bloxom area, Upton County. That's where the two wells are. 2000 in Taylor Draw, that's where we're headed. In Southern Midland Basin that's where we get to the 36 Wolfcamp A level wells, 36 Wolfcamp B level wells, for a total of 72 well inventory for the Southern Midland Basin.

And if I could just interrupt here just real quick. Block 5 in Crockett County, what's that position and how are you seeing offset activity there?

That's another position that's close to around 2300 net acres. Again, I'm going to be off a little bit, so don't hold me strictly to these numbers but I'm awful close there. And we're very much watching. Most of our Block 5 is in Atoka development. It's been a nice little development. But we are watching very closely what ConocoPhillips is doing right next to us.

If you recall, over a year ago now Conoco -- that whole area went for about $5,000 an acre in a University lease sale. Conoco has been down there drilling some wells now, and we're watching that quite closely and they're very close to our Block 5 acreage. So that -- we've always seen that to be somewhat on the edge, but we hope to be surprised by that.

Now, the other acreage area that we're focused on is in Borden County, and Fred's already told you that's about 15,000 net acres in Borden where we've drilled our Cline well and we've drilled our Miss well. Cline potential there is across the whole area is close to 120 wells. Miss potential is another 25 to 30 wells. And then Lynn County. Lynn County, if everything works the way we think it's going to work in the Cline for Borden, it will work in Lynn and that's another 6,000 net acres.

So, what I've left out is Carpe Diem, which is in Midland County, and that's net to Callon. That's 4 sections and we own about 85% of it. And that's where RSP just recently drilled a very nice looking Wolfcamp B well. It's about a 3800-foot lateral. They've got a really nice IP and a result out there and if that holds in there, that will add another 18 locations.

Okay. Very helpful, guys. Thank you.

Steve Berman with Canaccord Genuity.

Good afternoon, gentlemen. One more Lynn County question and Borden too, I guess. When earlier, Fred, you said things have really gotten leased up, up there, can I assume that includes into Lynn? If you had to go out and try and get a little more acreage, even though it's leased up, I assume you'd be paying a lot more than $696 an acre if you had to go in and try and get some more now?

The answer is yes. And I think Northern Borden is, I think, leased up pretty tight now. As you move up into Lynn, obviously, we were able to pick additional acreage up. But it is starting to get leased up as you move north, certainly, up through the Northern part of Lynn, as well. I do think the price is moving up, and right now you'd certainly think we'd be paying more than what we paid today.

Would it be into the several thousand, you think? Have you seen any recent transactions there?

No, not at this point, no. I think perhaps we're closer to $1,000 an acre, but I have not seen any at that level up here yet.

Okay. That was it from me. Thank you.

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Fred Callon for any closing remarks.

Once again, we do appreciate everyone taking time to call in. As always, if you have any additional questions, please do not hesitate to give us a call. Thank you.

The conference is now concluded. Thank you for attending today's presentation. Please disconnect your lines.