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Callon Petroleum (NYSE:CPE)

Q3 2012 Earnings Call

November 08, 2012 2:00 pm ET

Executives

Fred L. Callon - Chairman, Chief Executive Officer, President, Chief Executive Officer of Callon Petroleum Operating Company and President of Callon Petroleum Operating

Joseph C. Gatto - Senior Vice President - Corporate Finance

Gary A. Newberry - Senior Vice President of Operations

Bobby F. Weatherly - Chief Financial Officer, Executive Vice President and Director

Analysts

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Will Green - Stephens Inc., Research Division

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

Operator

Good afternoon. And welcome to the Third Quarter 2012 Results Conference Call. [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.

Fred L. Callon

Thank you. Good morning, and thank you for taking the time to call into 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.

Joseph C. Gatto

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, I'll turn it back to you.

Fred L. Callon

Thank you, Joe. We're pleased to report several key accomplishments in the Permian Basin that we believe will provide the foundation for a production 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 de-risked this acreage position. Combined with our Taylor Draw acreage, we have 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 their ongoing evaluation efforts on our properties in the Northern Midland Basin. To that point, we are currently completing our horizontal Cline well in Borden County with a lateral length of 6,679 feet. This 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 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 Borden 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 leasehold 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've continued to evolve our drilling program in the basin since 2010, via the horizontal development and the hydrated vertical [indiscernible] is a key drivers of efficient capital deployment within our portfolio. To that end, we will evaluate 3 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 2,100 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.

Gary A. Newberry

Thank you, Fred, and good afternoon. We continue to progress our horizontal development program focused on the Wolfcamp B in 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 of 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 3 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 de-risked 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 Ellenberger formation. The Shirly Newton 4801 will be tested in the Ellenberger formation, and pending those results, re-completed into the Mississippian formation. We've also drilled the Vickie Newton 3801H, our first horizontal Cline well, to a lateral length of 6,769 feet. We fractured stimulated the well this past week, and we are currently drilling out the 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 Shirly 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, 3 wells were completed in the third quarter, and are in the process of flowing back, and 2 additional wells are awaiting completion. We're about evaluating potential of deep results, completing 1 well to the depth of the Woodford interval and a second well in the deeper Atoka sands. At CH Ranch, 1 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 of 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 downtime to accommodate construction activities on Shell's Auger platform and an additional 7 days of downtime associated with Hurricane Isaac. Medusa experienced 9 days of downtime for Hurricane Isaac. Hurricane Isaac had minimal impact to shelf production. The Habanero #2 sidetrack 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 of 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 of oil equivalent per day. The variance in the third quarter of '12 is due to reduced downtime at Medusa and increased production in the Permian Basin, offset by scheduled downtime at Habanero and downtime associated with Hurricane Isaac. Production in the third quarter of 2011 averaged 5,261 barrels of 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 downtime at Habanero, along with normal and expected decline on the deepwater and shelf assets, downtime related to Hurricane Isaac, downtime on East Cam 257, all partially offset by growth in the Permian Basin. Production through the third quarter of 2012 averaged 4,251 barrels of oil equivalent per day compared to 5,182 barrels of oil equivalent per day through the 3 quarters of 2011. The variance in 2012 is due to the scheduled downtime at Medusa and Habanero, along with normal and expected decline in the deepwater and shelf assets, downtime 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 the 3 quarters of 2012 was $20,500,000 or $17.50 per BOE compared to LOE through the 3 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 of 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 are encouraged with the results of our first horizontal well in Upton County, our current multi-year inventory of horizontal well locations targeting the Wolfcamp Shale in 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.

Bobby F. Weatherly

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 after-tax losses related to mark-to-market derivative positions, net income was essentially breakeven for the quarter.

Operating revenues for the 3 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. 2/3 of the 18% decrease in oil and gas sales resulted from decreased production, which Gary has discussed. The remaining 1/3 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 cost. 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 in 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 3 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 approximately 1,670 barrels of oil per day hedged for the fourth quarter of 2012, with a weighted average ceiling and floor of approximately $92.50 and $123.50, respectively. For 2013, we have approximately 1,300 barrels of oil per day hedged, with a 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 of approximately 50% of our anticipated proven production on a 12- to 18-month forward-looking timeframe. We made 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. Largely contributing to the increase per BOE is that period -- 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 onshore reserve development, including the ongoing onshore development cost increases in the Permian Basin.

General and administrative expenses, net of amounts capitalized, were $6.4 million for the 3 months ended September 30, 2012, compared to $3.5 million for the same period in 2011. $2.6 million of the $2.9 million period-to-period increase is related to the noncash valuation adjustment required to adjust a portion of our non-dilutive cash settleable share-based long term incentive awards to fair value and non-recurring additional employee related cost, including some early retirement expense.

Interest expense on our debt obligations decreased 22% to $2.1 million for the 3 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 operational details for the third quarter of 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 of 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 of 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 Investors 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, our 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.

Fred L. Callon

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

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from Hsulin Peng with Robert Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

First question is, 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 maybe how many rigs do you plan to run given the success of your first 2 wells so far?

Gary A. Newberry

Yes, Hsulin, as you know, we've got a firm commitment for a 1 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 plan. So 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 hey if for some reason it doesn't work, then we'll be using that rig down in the southern part of Midland Basin on the stuff that we know that's fairly well de-risked. So that's about as firm a schedule as I think I can give you at this point in time.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. No, that makes sense. 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 oil -- getting your oil out to sales, is it a pipeline or trucking and any issue with the infrastructure?

Gary A. Newberry

Yes, Hsulin, 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's going on in the Northern Midland Basin, and I'll just go ahead and say that there's plenty of infrastructure up there for gas offtake, as well as oil offtake. Again, we'll 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.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. No, that's good. That's great. And then I guess the 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.

Fred L. Callon

Hsulin, this is Fred. We were very pleased with the acreage that we were able to pick up. I'll 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. So it is competitive, and I'd say, it's rapidly getting leased up. And there are 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.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. And then last question. Just in terms of the -- because I know you that are expecting meaningful resource adds at year end that should contribute to your borrowing base. So I was just wondering when can we expect an announcement on your borrowing base redetermination [indiscernible] for 2013.

Bobby F. Weatherly

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

Operator

Our next question is from Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Questions on the liquidity front. Hurricane downtime hurt you guys in the third quarter, you outspent your cash flow by a decent clip. 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?

Bobby F. Weatherly

I would say we're in that process right now of determining kind of 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. And once we really get a better grip on what that is, once we get -- 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 flipped [ph] the borrowing base in 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.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. All right. 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 in the Permian in terms of hooking up vertical wells and obviously on the horizontal side as well, the timing of those. You've got downtime in the Gulf of Mexico, so just a lot of moving parts, and I was hoping maybe you could just kind of script it out for how we should think about production, not throughout the entire 2013, but maybe just as we go from where we are today through the fourth quarter and maybe Q1, Q2. Any help there would be greatly appreciated.

Gary A. Newberry

Let me see how I can balance this out. I guess I can -- let's start with where I think I'm at today, for the month of October. That's not in our release, but the month of October, we produced right at 4,860 barrels a day, and that's kind of an up month for what we've had here recently. But that's the starting point, end of the first quarter we've got a significant impact in the Gulf of Mexico because of the Habanero well, where we're drilling 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 de-risked horizontal Wolfcamp B well 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 a minor decline at Medusa, because the Medusa redevelopment program has already been pushed back late into the year. If that helps you at all.

Michael Kelly - Global Hunter Securities, LLC, Research Division

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?

Gary A. Newberry

I would say at the pace that we're drilling, Mike, we would probably be bringing on a horizontal well about on average, 1 well every 35 days or so. So if that helps you kind of plan that out with a 1 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 -- 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.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. On the Mississippian, your offset operator, SM, has had some really nice success there. Just wondering if you could talk about what the read-through is for you guys. And know you are 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, which you should have done in late January.

Gary A. Newberry

Yes, by the time we get to the point of talking about the Miss, we'd be likely be talking about the Cline at the same time. So we see what SM is doing, just to the west of us. We're encouraged with those results that have been reported. We have now TD-ed our well and we're running casing on it today. So that's why I'm confident we're moving to Taylor Draw next. So 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. I would expect we'll be talking about the Cline in total before the end of January or mid-first quarter. [indiscernible]

Michael Kelly - Global Hunter Securities, LLC, Research Division

Real quick, what's the cost of that Habanero side track?

Gary A. Newberry

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

Operator

Your next question is from Richard Tullis with Capital One Southcoast.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

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

Gary A. Newberry

Habanero for October was right around 450 barrels a day.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. And then the sidetrack will add 900 roughly to that, net?

Gary A. Newberry

That's correct. Right now the #2 well is shut in, Richard. So it's been shut in since, I think, June or July because of some sort of a safety valve. We're actually plugging the bottom part of that well in the next couple of weeks to get ready for the up-dip redrill. So what I've just told you is producing from the #1 well, and it's producing fairly steady and that's a net number to us. So it's a pretty good well, and then the #2 well will come on at the end of the first quarter.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Will that add -- will it be more than 450 plus the 900, plus you're getting the #2 well back or?

Gary A. Newberry

No, no, no. The #2 well is actually the well we're actually sidetracking. So it will be the well that will come on with the new rig.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

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

Gary A. Newberry

Yes, for 2013, Richard, what we've been advised by the operators -- and remember, we gave you a good schedule in 2012 when that shifted because we've had a lot of noise in our 2012 production because of the variable timing of all this downtime 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 is pretty straightforward. They're abandoning the facility right now that, that pipeline used to terminate on or just moving the termination point and the tie-in point to another line to another facility. And 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 to July, August and September and it's 74 days total. 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. 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 -- Medusa's a significant asset to be off for a month and then once the new well at Habanero comes back on in late first quarter, that whole facility will be down for 74 days in the third quarter, so those are very impactful in 2013.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Right, right. 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.

Gary A. Newberry

Well, so what we paid attention to is what SM Energy has been telling us and we'd love to be able to report the same type of thing. I've got their latest release right here in front of me and on average within -- for 3 wells that they've reported, they've had a 7-day IP rate of 604 barrels equivalent per day and a 30-day rate of 540 barrels of oil equivalent per day. They're targeting $6.5 million a well. We're probably above that on our first well, but I can see how we can probably get there. But we'd 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 exists and where it doesn't. So only time will tell. This is a bit of a step out for us.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

And what did you say Medusa was producing in October?

Gary A. Newberry

It's right at 1,400 barrels of oil equivalent per day net.

Operator

Our next question is from Ron Mills with Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Question for you on the 7,000 acres that you added up in the Northern Midland Basin. I noticed 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?

Fred L. Callon

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

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

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 kind of 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?

Gary A. Newberry

That is correct, Ron. That's both of those projects. We haven't added any inventory for Carpe Diem yet and we know there's a pretty good result out there close to Carpe Diem that was announced by Diamondback. But that would be -- 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 de-risked area.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

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?

Gary A. Newberry

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.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then you broke down the Wolfcamp A and B. If you look at 2013, are you going to be more focused on Wolfcamp B drilling or do you think it could be evenly split between the 2 or is that still to be decided?

Gary A. Newberry

I want to get an early test at the Wolfcamp A, which is why when we go back to Upton County and drill actually off of our first pad drilling and we drilled 3 wells back to back to back with this nice gaseous [ph] rig. We'll want to get an early test at the A and then once we get that test, Ron, we'll drill about as efficiently as we can, driven by what we can add the best value to.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then -- I can't remember who's asking the question about the rigs. It sounds like if North Midland Basin works, you could have kind of a 2-rig program at some point next year based on the inventory and your internal capacity. Is a 2-rig program about as much as you would like to and/or be able to run in the Permian?

Gary A. Newberry

It would certainly be something I would've tried 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 the liquidity beyond 2013.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

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

Gary A. Newberry

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 assess reserve adds, borrowing base growth and getting our cost down to a very efficient manufacturing level. I think it comes down to just that.

Unknown Executive

Just going in, echoing what Gary said, and I think like [ph] the timing, as Gary said, the first quarter we'll be evaluating our Borden County and it really would be kind of the earliest sort of midyear if we want to add a second rig. And I think a combination of production growth we're seeing and the borrowing base that you're seeing this year. We've had 2 increases in the borrowing base and the borrowing base has almost doubled this year. And so we're seeing a really good impact on our borrowing base from the expanding 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 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 a second rig.

Operator

Our next question is from Will Green with Stephens.

Will Green - Stephens Inc., Research Division

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 maybe 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 2 wells up there?

Gary A. Newberry

We'll just had to kind of step back a little bit further, we kind of did a lot of petrophysical work before we got the acreage. We did a lot of correlation associated with the 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, these [ph] cuttings analysis and a lot of log analysis and evaluation porosity permeabilities, oil in place targets. And 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, that ought to work just as well or better than what's going on in Glasscock County. [indiscernible] It's got higher [indiscernible] target. It's got higher porosity. On the core that we did when we drilled the first vertical well, that validates all the things we kind of 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 1/3 of the acreage position in what we see today.

Will Green - Stephens Inc., Research Division

And then can we jump over the Neal wells? Talk about completion differences. I know that the first 2 fairly similar initial rates, seems like one had maybe 2 or 3 stages, seems like one may have been gel versus slickwater. 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 discernible 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 2 tests, but what's the recipe that seems to make the most sense based on any factor or any number of factors?

Gary A. Newberry

Will, that's a good question. And in fact, we'd 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 2 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 321, which was the first well, which had the higher IP, was the longer lateral and was fracture stimulated with slickwater and about 200,000 pounds of sand per stage, kind of the EOG model we were following. The second well is 651, which was slightly lower in IP and slightly lower in 30-day rates, 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've fracture stimulated it with a gel system, a linear gel system and increased the sand per stage to about 300,000 pound per stage. So it was only fewer stages because it was a little bit shorter lateral. So the main difference was slickwater versus gel, linear gel system. And that was really what we considered internally we call the Pioneer model, okay? So we consider 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 2 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 1. The linear gel frac is a little more expensive. So there's not enough material difference between the 2 wells for me to suggest that we ought to go do gel system fracs, so I would use slickwater. Now that's Gary Newberry talking without all the input from my team, but if that helps you quantify maybe at least the few differences that we saw at the time.

Will Green - Stephens Inc., Research Division

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. Maybe 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?

Gary A. Newberry

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 basin and 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 slickwater. And even with slickwater, 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.

Will Green - Stephens Inc., Research Division

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?

Gary A. Newberry

That could cost up to about $400,000.

Operator

Our next question is from Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

I 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, that more housekeeping item, walk through how you came to the acreage in Lynn County and any differences you're seeing on in seismic, et cetera, Lynn versus Borden and at this point?

Fred L. Callon

I guess, a couple of things. First the seismic, we do not have seismic in over this acreage, certainly in new acreage. We do have seismic over the 14,000, 15,000 acreage 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 kind of part of the basin. And so 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.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay, that make sense.

Fred L. Callon

Ryan, you asked about the net breakdown?

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

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

Gary A. Newberry

I'm going to give you some roundabout numbers, but I'm going be awful close here, okay? In Upton County, Upton County where we drilled our first 2 wells, we're right around 3,600 net. In Reagan County, where we're going to go next with the rig, we're right around 2,000 net. So Southern Midland Basin, around 5,600 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. So that's why 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 3,600 in the Bloxom area, Upton County, that's where the 2 wells are, 2,000 in Taylor Draw, that's where we're headed. So 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.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

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?

Gary A. Newberry

That's another position of close to around 2,300 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, and 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 the [indiscernible] 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 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, it's in Borden County. And Fred's already told you that's about 15,000 net acres in Borden, where we 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 and 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 is about a 3,800-foot lateral. They've got a really nice IP in the result out there. And if that holds in there, that will add another 18 locations.

Operator

Our next question is from Steve Berman with Canaccord Genuity.

Stephen F. Berman - Canaccord Genuity, Research Division

One more Lynn County question and on Borden too, I guess. When earlier, Fred, you said things have really gotten leased up, up there. Can I assume that includes into Lynn? And if you have 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 have to go in and try and get some more now?

Fred L. Callon

The answer is yes. And I think Northern Borden is I think leased up pretty tight now. And 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. And I do think the price is moving up. And to go out now, I certainly think we'd be paying more than what we paid today.

Stephen F. Berman - Canaccord Genuity, Research Division

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

Fred L. Callon

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

Operator

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

Fred L. Callon

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

Operator

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

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