Callon Petroleum Management Discusses Q2 2012 Results - Earnings Call Transcript

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 |  About: Callon Petroleum Co. (CPE)
by: SA Transcripts

Callon Petroleum (NYSE:CPE)

Q2 2012 Earnings Call

August 09, 2012 11:00 am 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

Analysts

Will Green - Stephens Inc., Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

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

Chris McDougall

Trevor Menke

Operator

Good morning, and welcome to the Callon Petroleum Second 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, please go ahead.

Fred L. Callon

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

Joseph C. Gatto

Thanks, 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 on our second quarter 2012 results news release and our filings with the SEC and can be referenced there on our website at www.callon.com for subsequent review.

I'll turn it back to Fred

Fred L. Callon

Thank you, Joe. Well, it's certainly an exciting time at Callon as we continue to grow our Permian operations, both in our vertical and now our horizontal drilling program. We continue to have good results from our Pecan Acres vertical drilling program with our first 4 wells producing a 30-day average rate of 190 barrels of oil equivalent per well, and we have 4 additional wells waiting to be completed. But the highlight of the quarter, of course, was our first horizontal Wolfcamp well. As we have transitioned the company onshore, I thought our days of well watching were behind us, but we've certainly been watching very closely our first Wolfcamp B well over the last several weeks. As we discussed in our recent operations update, our Neal 321H at our East Bloxom field had a strong 24 hour IP of 827 barrels of oil equivalent per day and continues to perform well. With this well result at our East Bloxom field and our new acreage position in the relatively de-risked area of Southern Reagan County, we've built an inventory of over 40 horizontal locations for development of Wolfcamp B. In addition, we continue to monitor industry horizontal activity in other Wolfcamp zones for potential development on our acreage in the Southern Midland Basin.

As we look at our Wolfcamp development program in the southern Midland Basin, our strategy has been to be a fast follower, benefiting from the learning curve that other operators have been building from horizontal drilling results in the region over the last couple of years. These learnings ultimately helped us to initiate our own program and commit a newbuild drilling rig on an accelerated timeline. As we continue to build our internal and geotechnical team and operational expertise, we positioned Callon to be an early mover in other parts of the basin that we believe are perspective for horizontal development. As a result of expanded mapping and other technical work by our team in the Northern Midland Basin, we acquired 14,470 contiguous acres in Borden County early this year. Since acquiring the acreage, we have seen a significant increase in both horizontal and vertical activity in this region. We view this area as the next potential growth catalyst for the company.

Over the next few months, we will be drilling 2 horizontal wells in Borden County, 1 targeting the Cline Shale, and 1 targeting the Mississippi line. If successful, we will have the potential to increase our horizontal rig program, 2 to 3 rigs and accelerate our growth plans in the future.

I'll 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'll then open the call for Q&A.

Now I'll turn the call over to Gary.

Gary A. Newberry

Thank you, Fred and good morning. I will start by highlighting results and progress related to our horizontal development program in the Permian Basin. As we reported in our operations update last week, 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. Early production results are very encouraging with 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. The peak 28-day average production rate since connecting the well into our production facilities is 598 barrels of oil equivalent per day. The well continues to flow at the surface with 400 pounds facing pressure. The Neal 651H, our second horizontal well in Upton County was drilled to a lateral length of 7,113 feet and is scheduled to be completed with 24 fracture stimulation stages on August 27. We are pleased with the drilling performance of our new generation drilling rig, the Neal 321H was drilled from spud to TD in 35 days, and the Neal 651H was drilled from spud to TD in 28 days.

Additional efficiencies are achievable once we move to pad drilling during full field program development. With these achieved efficiencies, combined with the recent addition of infrastructure and facilities, we believe that our future Wolfcamp B wells in this area can be drilled in 25 days with a total drilling complete cost of $7 million. We moved the drilling rig to our newly acquired acreage in Borden County in July, and have drilled and cased the Shirly Newton 4801 well. This is a vertical well drilled to 8,530 feet into the top of the Ellenberger formation. During the drilling, we cored -- we recovered 360 feet of whole core in the Cline, and 49 feet of whole core in the Mississippian. We also recovered rotary sidewall cores in the Wolfcamp and Spraberry formations. The Shirly Newton 4801 will be tested in the Ellenberger formation and pending those results, recompleted into the Mississippi formation.

We are currently moving the rig to the Vickie Newton 3801H, which is our first horizontal Cline well in Borden County. We have continued to see an increase in horizontal Cline activity in the northern Midland Basin and are looking forward to the results from this evaluation well. Following the first Cline horizontal well, we will drill a horizontal well in the Mississippian formation. Although our initial focus in this area was the Cline, we have become increasingly encouraged by the Mississippian potential after additional technical work and the recent horizontal drilling results approximately 11 miles to the west of our initial well location. These recently announced Mississippian horizontal wells have produced at an average 30-day rate of over 500 barrels of oil equivalent per day.

In the fourth quarter, we plan to move the rig to our Taylor Draw field, which is our newest acquisition in Southern Reagan County, to drill 2 Wolfcamp B horizontal wells. This is an area that has been significantly de-risked by encouraging industry reported results in the surrounding area. With these wells, we plan to drill a total of 6 horizontal wells in 2012, targeting 3 formations. The results of these wells will continue to be evaluated in the coming months and will provide the foundation for our drilling plans into 2013 and beyond.

To update you on Pecan Acres, the 30-day average rate for the first 4 wells was 190 barrels of oil equivalent per day per well, and the current average rate is 70 barrels of oil equivalent per day per well after 120 days of production. We have 4 additional wells drilled and waiting to be completed, 3 wells were drilled from the same pad -- 3 wells drilled from the same pad are scheduled to be completed on or about September 10. We intentionally delayed the completion of these wells to align with the drilling and commissioning of the salt water disposal system to minimize cost and trucking near the surrounding residential area. We will complete the drilling of the saltwater disposal well this week and move to another Pecan Acres development well prior to moving the rig to Glasscock County to drill 2 vertical wells on our CH Ranch acreage. Since completing our Bloxom horizontal well, net production from the Permian Basin has averaged 2,100 net barrels oil equivalent per day for the last half of July.

Moving to our Deepwater assets in the Gulf of Mexico, the planned 28-day downtime at Medusa was completed on June 9. At Habanero, the scheduled 60 days of downtime to accommodate construction activities on shale's Auger platform began on July 15. Also in the Deepwater, the drilling of the Habanero #2 sidetrack targeting approved, undeveloped reserves remains on track to commence during the fourth quarter of 2012, with first production targeted for first quarter of 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 expected to be restored by year end 2012.

Now turning to our quarterly comparisons. Our net production in the second quarter of 2012 averaged 4,107 barrels of oil equivalent per day, which was comprised of 60% oil and 40% natural gas and NGLs. This compares to production in the first quarter of 2012 of 4,308 barrels of oil equivalent per day. The variance in the second quarter of 2012 was due to the scheduled downtime at Medusa, partially offset by production at the Haynesville well following the repair and reactivation in late March and growth in the Permian Basin. Production in the second quarter of 2011 averaged 5,564 barrels of oil equivalent per day, which was comprised of 54% oil and 46% natural gas and NGLs. The variance in the second quarter of 2012 was due to the scheduled downtime at Medusa, along with normal and expected decline on the Deepwater and shelf assets, downtime on East Cam 257, all partially offset by growth in the Permian Basin. Production in the first half of 2012 averaged 4,208 barrels of oil equivalent per day compared to 5,141 barrels of oil equivalent per day during the first half of 2011. The variance in 2012 was due to the scheduled downtime at Medusa, along with normal and expected decline on the deepwater and shelf assets, the downtime on East Cam 257, all partially offset by growth in the Permian Basin.

On the expense side, LOE including severance for the second quarter of 2012 was $5.8 million or $15.57 per BOE. LOE for the first quarter 2012 was $8.8 million or $22.41 per BOE, which included the one-time cost associated with remedial work-over to restore production at the Haynesville well. LOE during the first half of 2012 was $14.7 million or $19.07 per BOE compared to LOE in the first half of 2011 of $10.3 million or $11.12 per BOE. Our LOE in the first half of 2012 was associated with the Haynesville remedial work and added wells in the Permian Basin. The LOE per BOE metric is further negatively impacted by production downtime at East Cam 257 and Medusa.

Turning now to our 2012 guidance. Our current estimate for 2012 capital expenditures is $152.5 million, an increase of $13.5 million to expand infrastructure for our horizontal drilling initiatives and increased expenditures to acquire additional acreage in the Permian Basin. Production for the third quarter 2012 is expected to range between 4,500 and 5,000 net barrels of oil equivalent per day. Production for the third quarter will be impacted by the scheduled downtime at Habanero and continued downtime at East Cam 257. Production guidance for 2012 remains unchanged and is expected to range between 4,500 and 5,000 net barrels of oil equivalent per day. LOE, including severance packages 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 and I am pleased with the efficiency gains achieved during the drilling of our second well. We will incorporate these learnings into our development plans for Borden and Reagan County, as we continue to fully define the opportunities on our newly acquired acreage. Our current multi-year inventory of horizontal well locations provides for significant value-added growth in the Permian Basin.

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 second quarter 2012 results of operations as we reported in yesterday's earnings release. For the second quarter of 2012, the company reported net income and fully diluted earnings per share of $3.8 million and $0.09, respectively. Excluding the after-tax gains related to the early extinguishment of debt and mark-to-market derivative positions, Callon reported net income of $0.4 million and diluted earnings per share of $0.01 for the second quarter of 2012. Operating revenue for the 3 months ended June 30 included oil and natural gas sales of $25.4 million from average production of 4,107 BOE per day. These results compare with $36.8 million from average production of 5,564 BOE per day dig the comparable 2011 period. 22% of the 31% decrease in oil and natural gas sales resulted from decreased production, which Gary just discussed. The remaining 9% relates to price. The average price per barrel of oil in the second quarter of 2012 was $98.78 compared to $105.75 during the same period in 2011. Our oil price realizations exceeded NYMEX by $5.29 per barrel in the second quarter of 2012, due to hedging impact and the premium received on our offshore production, partially offset by Permian Basin differentials. The average price realized per 1,000 cubic feet of natural gas in the second quarter of 2012 was $3.65, compared to $5.58 during the second quarter of 2011. Our natural gas price realizations on a BTU equivalent basis exceeded NYMEX by 55% in the second quarter, primarily due to the value of our ECL in our natural gas stream from both our Permian and offshore productions.

On a combined hydrocarbon equivalent basis, Callon received $67.85 per barrel of oil equivalent for the second quarter, compared to $72.75 in 2011. As discussed in our 10-K, at the beginning with 2012 derivative context, the company elected to no longer designate derivative contracts as accounting hedge. Unrealized gains on mark-to-market derivative instruments, net for the 3 months ended June 30, 2012, were $3.5 million compared to none in 2011, when all derivative contracts were designated as hedgings for accounting purposes. We currently have approximately 1,650 barrels of oil per day hedged for the second half of 2012, with a weighted average ceiling and floor of approximately $92.50 and $123.50, respectively. For 2013, we currently have approximately 1,300 barrels of oil per day hedged with a weighted average ceiling and floor of approximately $90 and $116, respectively.

Regarding natural gas, we entered into a swap transaction in June for a volume of 3,000 MMBTU per day for the October 12 to December 13 term, at a price of $3.52. We simultaneously entered into the sale of a put contract in Callon for 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. These option sales allowed us to increase swap price received for the 15-month period beginning in October 2012. Presently, we have no NGL hedges in place. We will continue to monitor available hedging structures and as always, we have a targeted hedging of approximately 50% of our anticipated improved production on a 12 to 18-month forward-looking timeframe. We may decide to increase this target in the future as we continue to progress our horizontal drilling initiative in the Permian Basin. Depreciation, depletion and amortization or DD&A for the second quarter of 2012 was $11.8 million compared to $13 million in 2011. The overall decrease is attributable to the 26% drop in total production for the second quarter of 2012 compared to 2011. Partially offsetting this decrease was a rate increase of $31.69 per BOE for the second quarter of 2012, compared to $25.58 per BOE for 2011. The rate increase relates to the impact of a 2008 impairment charge following its ceiling test writedown which resulted in a lower prospected DD&A rate for existing reserves at that time. Subsequent increases in the rate are attributable to our planned exploration and development expenditures related to our onshore reserve additions, primarily the Permian Basin.

General and administrative expenses, net of amount capitalized, increased $4.4 million in the second quarter of 2012, from $3.8 million for the same period in 2011. The increase relates primarily to higher compensation-related expenses as we add to our technical staff to support our onshore growth and 100% Permian operating production. In addition, we experienced a higher expense for services related to leasehold acquisitions.

Interest expense on Callon's debt obligations decreased 12% to $2.4 million for the second quarter of 2012, compared to $2.7 million for the same period of 2011. The decrease was due to higher capitalized interest resulting from an increase in our own evaluated properties inventory and the early extinguishment of $10 million of 13% senior notes. As noted, during June 2012, the company redeemed 10 million [ph] base amount of its 2016 senior notes with a carrying value of $11.6 million, including $1.6 million of deferred credit for $10.2 million. This resulted in a $1.4 million net gain on the early extinguishment of debt. Please review our earnings release and 10-Q for further results of operations detailed for the second quarter of 2012.

As Gary discussed, we recently increased our 2012 capital budget to $152.5 million from $139 million. This capital budget will be funded from cash flow from operations and existing liquidity, including our borrowing base facility. As we look forward to 2013 and beyond, we're very focused on proactively increasing our liquidity position as we together plan for success. Given the strength of our balance sheet, which has been built over the last 3 years, including the $75 million equity offering in 2011, combined with our strong earnings during this period, we have the capacity to add incremental leverage to execute our Permian development program while enhancing shareholder return. So basically, we have tripled our borrowing base since the beginning of 2010, as we have increased our onshore proved reserve base. And while it's difficult to estimate the amount and timing of any borrowing-based increase, we believe that continued improved reserve growth, including the results in our horizontal drilling program will be a catalyst to add incremental borrowing base in the future. Also under our recently signed secured credit agreement executed in June, we have the flexibility to incur additional unsecured debt or preferred. Our existing 13% senior notes become callable in September. We will remain conservative in our financial strategy, especially during times of price volatility. We continue to experience the realities of drilling in new areas of the Permian Basin. Depending on the pace of our drilling program over the next several quarters, which is currently 100% operated, we may be in a free cash flow negative position at time. This will obviously create funding needs that could be addressed with the debt options which I just discussed. However, we will continue to plan our drilling activities on the basis that will allow us to maintain a reasonable debt to EBITDA ratio. The divestiture of non-core assets in the future to fund the acceleration drilling plans remains an option as we grow critical mass in the Permian.

Now I would take a minute to discuss guidance for the second quarter, and the full year 2012. As Gary mentioned earlier, we project the daily production rate for the full year to be 4,500 to 5,000 BOE per day, with oil accounting for approximately 63% of the projected production for the full year. For the third quarter, we are projecting a range of 4,500 to 5,000 BOE per day. We are projecting general and administrative expenses to be in the range of $18 million to $20 million for the full year of 2012, and $4.6 million to $5.1 million for the third quarter. Hedge interest is forecast to being $12.5 million to $14 million for the year, and $3 million [ph] and $3.4 million for the third quarter. For the full year 2012, the amortization of the deferred credit, which is recorded as the 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, and the third quarter should be in the range of $31 to $33 per BOE. Please refer to our guidance press release, which provides additional detail regarding guidance in the third quarter, and full year of 2012. This guidance will also be posted on our website in the Investors section.

Now I'll turn the call back to Fred for any final comments.

Fred L. Callon

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

Question-and-Answer Session

Operator

[Operator Instructions] The first question comes from Will Green with Stephens.

Will Green - Stephens Inc., Research Division

I know it's still early, do you guys have any early EUR estimates on what that particular well will look like?

Gary A. Newberry

Will, this is Gary. As you've mentioned, that we are very encouraged and we're certainly looking. When we first started talking about this play, we had a range of 350 to 500 MBOE per well. And certainly looking at our initial results, we believe we're in the upper end of that range and actually, we're actually looking now at all the other published data that we can look at because as we look at information coming from other companies, that range may be expanding significantly on the upside. So we haven't fixed in on a number yet but we're very encouraged with it.

Will Green - Stephens Inc., Research Division

Well, it definitely looks great early on, so I just wanted to get your comments on that. Did you guys use gel or slickwater whenever you completed that?

Fred L. Callon

Will, again, as we've said, we've looked across the industry and we wanted to learn as much as we can before we ever drilled our first well, or to actually enter the play at the top of the learning curve. And we've seen a lot of companies that have done quite well with slickwater and then we've seen really the Pioneer results, I'll just mention their name because they're the ones who seem to be doing exceptionally well with linear gel fracs. We frac-ed our first well with slickwater and we kind of did it the way many in the industry are doing now and we're very pleased with those results but I'll just preempt the next question given what Pioneer is seeing, we'll likely frac our second well at the end of this month with the linear gel system.

Will Green - Stephens Inc., Research Division

Great. Well, it'll be a nice heads up test then. And then, I don't know if you guys have gotten this far yet but on the first horizontals into the Cline and the Mississippi that you've talked about, what kind of lateral link are you guys targeting, how many stages, what can we expect there?

Gary A. Newberry

Will, again, trying to enter the play at the top of the learning curve for the industry, we see that the key players in the Cline, they're in Glasscock County, are now regularly getting out to 7,500 feet and we're going to start out with that in mind. We're planning to go to 7,500 feet, and we'll certainly list in to the hole all the way and get as far as we can. We certainly think that's achievable given the rig we have and the crews we have on that rig. And at least what we know of how to drill the Cline. We've talked to a lot of people, we've looked at from a technical perspective and we believe we'll get there. And with that in mind, 7,500 foot lateral will go right back to another 27 to 30 stages of fracture stimulation for the Cline.

Will Green - Stephens Inc., Research Division

Okay. And then on the Miss, is that going to be similar?

Gary A. Newberry

The Miss, again, is very similar. It's a little different on the completion side but we're going to target 7,500 feet. We're paying a lot of attention to what's going on in the Miss just 10 miles to the west of our current stakes location. They're getting very good early results. The recently announced results on those wells were quite interesting and encouraging but we're in a target of 7,500-foot lateral. It's a thinner section, it's about 120 feet thick. We believe we'll be able to do that and the fracture stimulation of the Mississippi line is a little different than the shale play. So we'll be looking more closes [ph] to around, I'd say, 15 to 20 stages of fracture stimulation across that horizontal lateral.

Operator

The next question comes from Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

The question is on liquidity. Bob, you gave some color on what you're looking at in terms of options but obviously, the opportunity set on the Permian right now looks to be great, and you're looking to accelerate your drilling there but you are on pace to have negative free cash flow in the second half of the year and you've got $50 million right now building the revolver. Maybe you could just give a little bit more color on what your options there, what the likely strategy is for you. And then also with that, when would you potentially look to add a second rig to deploy horizontal rig?

Bobby F. Weatherly

Well, to your first question, I think we've been pretty clear that we feel very comfortable funding even our increased CapEx budget with both our existing liquidity and our cash flow from operations and as Gary said, second half of the year, the back end of the year will benefit from some things that the front end of the year didn't. For example, Medusa was down for a month, that's a big deal. Also we've given some of the color on what the production is out of the first horizontal well, we'll be frac-ing our second one fairly soon. And we got a number of Pecan Acres wells that are to be frac-ed and all of which have very good production. So from a production standpoint, operating cash flow standpoint, we believe that'll be good and we think also, as we've said, we've seen a continued increase in our proved developed reserves. We're reviewing that now and we would look to our borrowing base hopefully to move ahead. So I think we feel very comfortable with adequate funding for our programs that we have. As far as the idea of adding a second rig, I think that is a work in process. That Gary has been very clear, I think, by saying that he wants to get out there, he wants to see what we really got in the Cline, we decided to go to the Mississippian, let us see what we have there and plus we've got these 2 wells down at Taylor Draw that he'll be drilling in the latter part of the year but still we'll have more results. So even though we may be a fourth -- in the fourth quarter really laying out our program and what our expectations are for all of these properties, it'll be what we find and reality of what we see will determine our pace of drilling and when we would bring on the second rig.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. All right, great. And then if you could help me out, thinking about the Gulf of Mexico, I know we got a lot of moving parts right now with Habanero down for 90 days, then the sidetrack in Q4 there in East Cam being shut in. But once you get through all that and into '13, what's kind of the normalized production rate that we should really factor in for the Gulf of Mexico? Is everything sorted out there?

Fred L. Callon

For the Gulf of Mexico. Let me think through that. By the time we get to the end of the year for the Gulf, now we're currently at Medusa, we're around 1,500 net barrels a day. We got Habanero coming on. The #1 well is still making around 400 net. The #2 sidetrack will come on gross around -- our prediction is somewhere around 9,000 barrels of oil equivalent per day gross, but our net of that would be close to around 900. The shelf continues to go ahead and decline a little bit but we're still producing around 1,100 net barrels equivalent of gas today and East Cam 257 is off and it will be back on by the end of the year. All that work associated with bringing that back on is probably right on schedule for the end of the year. So I don't know how to add all that up, but it'll be pretty significant.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Got it. What could we add in for East Cameron coming back on?

Gary A. Newberry

That was producing 1.8 million steady net to Callon. So that's 300 equivalent a day. So that'll come on at the end of the year. That's all gas now, very little -- limited liquids on that.

Operator

The next question comes from Ron Mills with Johnson Rice.

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

Gary, on the Permian, the Bloxom acreage, obviously, you have -- your results, you had Gulf Port announce an offsetting well yesterday. That area, I think everyone is pretty much considered de-risked at this point. Can you point to some offset operator activity? It sounds like Devon and others have been drilling closer to your Kayleigh areas, some drilling offsetting Carpe Diem, even some activity down on your Block 5 acreage, acreage that initially you weren't -- that you may not have considered as perspective as East Bloxom but now with industry activity, can you point to some of the offsetting activity there and also in Reagan County, where I think one of the recent Pioneer wells was also announced?

Gary A. Newberry

We are very encouraged still with even the acreage we're not talking about with respect to horizontal work in around Kayleigh, Carpe Diem, Pecan Acres, Block 5. There's a lot of activity going on very near us. I think, Devon actually announced a well that was drilled 9 miles north of our Kayleigh prospect and about -- that would be about 15 miles south of our Carpe Diem in the middle of Wolfcamp. That was several months ago, they announced that they had drilled a 4,000-foot lateral and it had IP-ed at 400 barrels of oil equivalent per day. So that was very encouraging for moving further north with the Wolfcamp play in the Midland Basin. That was one of the most -- very interesting results that came out here just recently. They then turned right around and drilled a 7,500-foot lateral immediately to the east of our Kayleigh section. We have no results from that well yet. We don't know if it's completed yet but we're very encouraged with that activity that close to us because it's right next door. As far as Carpe Diem, where we have 4 contiguous sections, we know that there's a horizontal well going along in the middle Wolfcamp again by another operator and that well should be down by now. It won't be completed but we're pretty sure it's been drilled and that same company is actually permitted another middle Wolfcamp well and they're talking about drilling even a Cline well. So we're anxiously awaiting a lot of that results to even consider the additional potential and growth opportunity that, that leads for us there at Carpe Diem because that's laid out quite nicely for 7,500-foot laterals. And then in Block 5, the furthest southern part of our acreage position in the Permian, ConocoPhillips is actively drilling now near that acreage. And so it'll be interesting to see how all that information kind of evolves over the next 6 months and what that means for additional running room for Callon in 2013 and beyond. And then in Reagan County, where we just acquired 1,800 net acres, that lies out -- lies in there nicely for about 19 horizontal wells in the Wolfcamp B. You're right, Ron, that's right next door to the exceptional results that Pioneer just announced on some of their University 10 wells in their recent publications. So we're very encouraged with everything going on around us. And of course, most of that's just focused on one lens of Wolfcamp B. There's -- the other part of that is there's more and more information coming out about the Wolfcamp A, which may actually open up an entire new level of horizontal development on the acreage that we currently have.

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

And moving up to Borden County, on the vertical well. It sounds like you took quite a bit of core in the Cline and the Mississippi is a little bit thinner but less core. Any color you can provide on your initial observations from the core data as you drill down to the Ellenberger there?

Gary A. Newberry

Yes, I can give you some. One, of course, we've been excited about the area simply because of all the petrophysical work that we had done with new tech engineering and our own technical team. We always saw that there was good porosity on logs, good saturations in the logs. We always kind of solved in cuttings and sidewall for us from all wells that it was very perspective. And I guess, what I'll say is that the core validated all that. The other interesting thing about coring decline is it cored quite well, it cored fast, we got good recoveries, it was a very confident formation. But that fast drilling is another indication of good porosity. As far as the Miss goes, even though we got less recovery, the good thing was it was -- part of that less recovery was it was kind of broken up at the top of the formation. That's a good thing. It's a good indicator that you've got real good porosity where you need it in the Miss to make that work. So at the end of the day, the core kind of validated our enthusiasm for the area. We'll be a month or 2 before we do the full core analysis, the lab analysis on all the entire core section and then we'll be able to validate that analysis with actually some real production results from the Cline -- first Cline well in just a few months. So no big surprises with the core because I guess, the headline is it's kind of validated what we expected.

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

Good. And then from a timing of completion standpoint, obviously, the Neal #2 here is next but where are you in terms of potentially scheduling the completions up in Borden and also down in Reagan County. If you'll get 6 wells drilled this year, how many do you expect to actually have online by yearend?

Gary A. Newberry

We'll certainly have the Cline well online by yearend in Borden County. I'm not quite certain exactly about the Miss well, I think it'll be coming on right towards the end of the year. But the current [ph] wells -- or the 2 Taylor Draw wells in Reagan County, we'll likely get those drilled but probably not completed this year but it will be certainly first thing in 2013. And of course, we would expect similar results out of those wells that we have just achieved out of the Bloxom area.

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

Okay. And then one last one for me. In terms of potential drilling locations in your Permian, you now have over 28,000 acres and just looking at one horizontal zone, is that -- you still thinking 150 plus or minus-type locations and to the extent you have Cline opportunities and some portions are multiple Wolfcamp opportunities, that number is higher or am I double counting?

Fred L. Callon

No, Ron, if I count locations in a single Wolfberry zone in our southern -- in our currently de-risked southern midland area, I can easily get to 41 additional locations in the southern basin. You take that to 2 levels and you get to 82. I think I did that math right. And then up in Borden County, planning for success in the Cline and we're encouraged with that. The way we've currently got a development plan laid out for Borden County, we've got over 100 locations, about 120 identified Cline locations and then, pending the results of this Mississippian well, we'll add on to that. So yes, we've got an inventory today of over 150, pending success in Borden County, on a single level of horizontal potential.

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

Does that southern Midland basin include only around that East Bloxom area or is that including Reagan and Kayleigh and Carpe Diem opportunities?

Gary A. Newberry

That southern Midland numbers that I just talked to you about was simply Bloxom and the new acreage in Reagan County. I think that's fairly well de-risked. It doesn't include anything in Carpe Diem, Kayleigh, Pecan Acres or Block 5.

Operator

Your next question comes from Chris McDougall with Westlake Securities.

Chris McDougall

So with your bond redemption that you talked about on the call, I guess, I just wanted to understand the thought process behind redeeming 2 million of those and then if we should see that going forward, kind of similar a rate or if this is a one-off deal?

Bobby F. Weatherly

I think it was clearly a one-off transaction. We had the ability -- we had a situation where we could bottom in at what we felt like was a very good price. I think our view of it was that buying in $10 million saved us $1.3 million cash interest on a year basis and so that was our big motivation. It also got the total down, it reduced our debt, gave us some optionality as we move forward and what we might do out here later on. But that's not something we plan on doing as a part of our program going forward.

Chris McDougall

Okay. Great. Now that makes sense. And then secondly, before, you've talked about your Gulf of Mexico non-op positions as being great assets but maybe not core to the company and you'd be kind of open to selling those at the right price. Have you been entertaining any offers? How does the scenario look for both acquiring and disposing of assets, broadly?

Fred L. Callon

Well, I guess, the answer is that of course, we need -- we always separate our 2 Deepwater assets, Medusa and Habanero, from our Shelf. Our Shelf is -- again, it's mostly non-operated, it's strictly gas, and given gas prices, we just felt like it's better to produce it out given the market for that type property. With respect to Medusa and Habanero, as we said, these are both world-class kind of assets, primarily oil, a lot of reserve life. As we've talked about Habanero, we've got an opportunity -- a pretty low risk opportunity here, sidetracked as well and we think have a nice bump in production next year. So we are comfortable with Medusa and Habanero as being long-life haul assets that will generate significant cash flow for us to reinvest in the Permian in the coming years. Having said that, we certainly would entertain, I mean, strategically, we are shifting onshore. So we would entertain opportunities. We have not -- we're not in active negotiations with anyone to sell those assets because quite frankly, there's so much behind pipe and upside in the fields. What we're not interested in doing is selling properties based on today's production or fuel sort of PDP type value but if someone at some point want to pay us for the upside in those fields, we'd certainly entertain that.

Operator

The next question comes from Trevor Menke with Robert W. Baird.

Trevor Menke

I'm just looking to get a little clarification on the $152.5 million CapEx number. Does that include the $12 million of acreage you closed on in July or no?

Fred L. Callon

Yes.

Operator

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

Fred L. Callon

Great. Once again, we appreciate everyone taking the time to call in. I appreciate all the questions and in the meantime, if you have any questions, please don't hesitate to give us a call. Thank you.

Operator

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.

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