NATCHEZ Sep 4, 2015 (Thomson StreetEvents) -- Edited Transcript of Callon Petroleum Co earnings conference call or presentation Friday, August 9, 2013 at 3:00:00pm GMT TEXT version of Transcript ================================================================================ Corporate Participants ================================================================================ * Fred Callon Callon Petroleum Company - Chairman and CEO * Joe Gatto Callon Petroleum Company - SVP Corporate Finance * Gary Newberry Callon Petroleum Company - SVP of Operations * Bob Weatherly Callon Petroleum Company - EVP and CFO ================================================================================ Conference Call Participants ================================================================================ * Will Green Stephens Inc. - Analyst * Ryan Oatman SunTrust Robinson Humphrey - Analyst * Gabriel Daoud Sidoti & Company - Analyst * Tim Rezvan Sterne, Agee & Leach, Inc. - Analyst * Jeb Bachmann Howard Weil - Analyst * Hsulin Peng Robert W. Baird & Company, Inc. - Analyst * Mike Kelly Global Hunter Securities, LLC - Analyst * Ron Mills Johnson Rice & Company - Analyst * Philip Dodge Noble Financial - Analyst * Adrian Fekula Brean Capital - Analyst ================================================================================ Presentation -------------------------------------------------------------------------------- Operator [1] -------------------------------------------------------------------------------- Good morning, and welcome to the Callon Petroleum second quarter 2013 results conference call. All participants will be in listen-only mode. (Operator Instructions) After today's presentation, there will be an opportunity to ask questions. (Operator Instructions) Please note this event is being recorded. I would now like to turn the conference over to Mr. Fred Callon. Mr. Callon, please go ahead. -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman and CEO [2] -------------------------------------------------------------------------------- Good morning. And thank you for taking time to call in to our second quarter 2013 results conference call. Before we begin, I want to remind our listeners that presentation slides accompanying this call are available on our website under the events and presentations section. I would now like to ask Joe Gatto, our Senior Vice President of Corporate Finance, to make a few comments. -------------------------------------------------------------------------------- Joe Gatto, Callon Petroleum Company - SVP Corporate Finance [3] -------------------------------------------------------------------------------- Thank you, Fred. At this point, I would direct listeners to page 2 of the presentation materials. We would like to remind everyone that this conference call contains forward-looking statements which may include statements regarding our reserves, as well as statements including the words believe, expect, plan, and words with similar meaning. The 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 report on Form 10-K available on our website or the SEC's website. We may also discuss non-GAAP financial measures such as discretionary cash flow, PV10 measure, and adjusted net income. Reconciliation and calculation schedules for such non-GAAP financial measures are available in our second quarter 2013 results and news release and our filings with the SEC and can be referenced there on our website for subsequent review. -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman and CEO [4] -------------------------------------------------------------------------------- Thank you, Joe. I will start with a few highlights on page 4 of the materials. As we discussed in past calls, our evolution to the horizontal development of our resource base is key to our growth plans and acceleration of resource value for our investors. Our horizontal program is over a year into its execution and we have demonstrated consistently strong well results with our program development in Upton and Reagan Counties. We currently have five producing upper Wolfcamp B wells in the southern Midland Basin area that had an average initial 24-hour production rate of 925 barrels of oil equivalent per day and extended period production that has exceeded over 450,000 barrel of oil type curve. With experience we have gained as a horizontal operator in the Permian, we are now well positioned to accelerate the pace of our activity targeting over 13,300 net acres in the southern and central Midland Basin prospective for several zones of development. Following the issuance of perpetual preferred equity in May, we recently added a second horizontal rig to develop our acreage. Our first rig will continue program development of the East Bloxom and Taylor Draw fields while the second rig will focus on our Carpe Diem field in Midland County and our newly acquired Garrison Draw field in Reagan and Upton Counties. Our activity will remain weighted to development of upper Wolfcamp B in the near term but we are currently testing the lower Wolfcamp B and Wolfcamp A, as Gary will discuss in more detail. While we believe this drilling program will drive meaningful growth over the next few years, we recognize that continuing to expand our inventory of locations is critical to long term value creation. We've done an extensive analysis of our properties, correlating our subsurface data well results and emerging plays across the Permian Basin to develop a high-graded view of our multi-stack potential. Based on this work, we believe we have over 10 years of drilling inventory in the southern and central Midland Basin alone, assuming a two rig horizontal program. In addition, our delineation of our northern Midland properties continues with a vertical S well spud in the last few weeks. Turning to slide 5, we've provided a summary of our current inventory of horizontal drilling locations in the southern and central basin. Additional support data is available in the appendix for your review. Our team has identified approximately 270 locations targeting five zones with proven well results from Callon and other offsetting operators, given the importance of understanding the depth of our inventory before making the decision to add a second horizontal rig. This was an analysis that demands a high level attention from our technical team. It was not a simple math exercise. Based on our detailed work to date, including micro-seismic analysis in the southern Midland Basin, we believe over two-thirds of our acreage position in this part of the basin is prospective for Wolfcamp A and upper Wolfcamp B, and roughly half is prospective for the lower Wolfcamp B and lower Spraberry in areas where the intervals demonstrate adequate thickness. In total, this inventory represents over 65 million barrels of resource potential on a net basis assuming the low end of EUR estimates. Page 6 provides a snapshot of the impact of our increased level of activity is forecast to have on our production and PDP reserve base. Although the impact to our second drilling rig will be weighted to the end of 2013, we are targeting a 500 barrel equivalent per day increase in our targeted production -- our targeted Permian exit rate to 3,500 barrels of oil equivalent per day to this year-end based on some contribution from the second rig but also improved performance from our base production. We also forecast an annual increase or approximately 145% in our PDP reserve base in the Permian at year-end, firmly establishing cash flow in properties in the basin. As we look out to the end of 2014, we project our exit rate in the Permian would be approximately 5,750 barrels of oil equivalent per day based on our existing type curve. While there is obvious uncertainty in longer range production estimates created by unforeseen changes in schedules and the accuracy of forecasting the impact of shut-ins during completions, we believe this estimate is an achievable one based on the proved capabilities of our operational team. I will now turn the call over to Gary Newberry, our Senior Vice President of Operations, for an operations update and discussion of recent well results. Gary? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [5] -------------------------------------------------------------------------------- Thanks, Fred, and good morning. I will pick up the discussion on slide 8 with a review of our recent activity in the Permian Basin. Starting in the southern Midland Basin, our horizontal program development of the East Bloxom and Taylor Draw fields has begun to hit its stride. We drilled five wells during the quarter bringing our total horizontal wells drilled for the year to a total of nine. Seven of these wells targeted the upper Wolfcamp B shale with one targeting the Wolfcamp A and lower Wolfcamp B. Importantly, we continue to drill wells with over 7,000 feet of lateral length in 20 days. On the completion side, we completed four wells during the quarter and currently have seven wells in various stages of completion. We are starting to see the benefits of our investment in water infrastructure at East Bloxom and Taylor Draw which will position us to accelerate the pace of our completion schedule as the year progresses. As Fred mentioned, we added over 2,000 net acres to our southern Midland position with the acquisition of the Garrison Draw field in Reagan and Upton counties. This field was producing approximately 145 net barrels of oil per day at the time of acquisition from existing vertical wells. This past week we moved the newly acquired second rig to this acreage to commence a horizontal well targeting the upper Wolfcamp B. In the central Midland area, the vertical deepening program has been progressing well at the Pecan Acres field with two wells on production and a third in the process of flowing back. The contribution from the zones below the Atoka in this area are driving strong production results as demonstrated by an initial 24-hour rate of 520 barrels oil equivalent per day from the Pecan Acres 23-11 well. We have drilled two wells with a similar deepening concept at our Carpe Diem field and will be completing them in the third quarter. As mentioned earlier, we will be adding horizontal development drilling to our central basin activity later in the third quarter. Our positive view of the prospectivity of both the Carpe Diem and Pecan Acres fields has been supported by offsetting results in Midland County from both Wolfcamp B and Wolfcamp A wells. We will also continue to monitor surrounding industry activity targeting shallower zones such as the lower Spraberry. Our initial drilling will be focused on the Wolfcamp B and should provide the base for another area of program development to add to our current southern Midland activity. Rounding out my review of recent Permian activity, I will now discuss the northern Midland Basin. Our team has continued to work on our delineation of our Borden County position from data gathered from our vertical and horizontal exploration wells as well as analysis of core samples taken in the area. We are progressing our evaluation of the Borden County acreage position with the recent spudding of a vertical well testing the Mississippian concepts that we have developed. After the evaluation of this well, we will be positioned to finalize our future plans for Borden County. In addition, we will begin our evaluation efforts in Lynn County in early 2014. Moving to slide 9, we have summarized the results of our horizontal development drilling program to date. At East Bloxom, our focus has been on longer laterals up to 7,500 feet with an average demonstrated initial rates of over 1,000 barrels oil equivalent per day on a peak 24-hour basis and over 600 barrels oil equivalent per day on a peak 30-day basis. We currently have four horizontal Wolfcamp wells in various stages of completion with the Neal 341H, our first Wolfcamp A well currently being fracture stimulated. At Taylor Draw, our initial wells have been drilled as shorter laterals on the eastern side of the field. As can be seen on the chart on the right side of the page, we plan to have four upper Wolfcamp B wells online by the end of August in this field including our first well, the Pembrook 9121. We are also in the early stages of production on our first lower Wolfcamp B test, the Weatherby 1H. The well produced at a 24-hour rate of 860 barrels of oil per day during the most recent tests where the well was flowing back. This rate, combined with the results of our micro-seismic analysis performed at the field, gives us encouragement for another de-risk bench of development in the basin. As we look forward to our next round of pad development at Taylor Draw, we will be drilling 7,500-foot laterals on the western side of the field. I'll now turn to slide 10 which provides well data on our first two deepened vertical wells at the Pecan Acres field in Midland County that have been on production for an extended period of time. The chart on the top is the Pecan Acres 23-3 well which was initially completed in four isolated deep zones down to the Woodford. These zones produced at peak rates of just under 150 barrels oil equivalent per day before we reentered the well and recompleted the traditional up hole zones. The chart on the bottom depicts the Pecan Acres 23-11 well which was completed in all 12 target zones. As you can see, this well has performed beyond expectations with an initial peak 24-hour rate of 540 barrels oil equivalent per day. As I mentioned earlier, we have three wells with similar target plans currently in the process of being completed, two of which are in the Carpe Diem field. Overall, we believe our ongoing high-graded vertical program will continue to provide a good complement to our horizontal activity. These vertical wells provide competitive returns on capital when infrastructure is taken into account and also allow us to exploit deeper zones that are currently not as economic to develop on a horizontal basis at shallower zones such as the Wolfcamp. Based on review of our identified vertical inventory of 116 40-acre wells, we believe over 50 of these locations have deepening potential. Slide 11 provides some recent highlights from our offshore asset base. The Medusa field returned to production in early July following 23 days of down time in June per scheduled Downstream pipeline maintenance work. During the shut-in period, three existing wells underwent stimulation operations and other routine maintenance was performed. The field is ramping up while testing continues and the field is currently producing at a rate of approximately 1,100 barrels oil equivalent per day, net to Callon. We are seeing positive response from the stimulation work that was performed in both terms of higher flowing bottom hole pressures and higher initial rates. Additionally, we anticipate that production from two wells will be further optimized with gas lift in the coming months. Our Gulf of Mexico shale production received an increase in the second quarter as the East Cameron 257 field was returned to production after being shut in for over a year for pipeline remediation. The field is producing approximately 275 barrels oil equivalent per day on a sustained basis after being brought back online in early May. After our recent abandonment of the Mobile Bay 864 field, our current shelf portfolio is comprised of five non-operated fields which produced an average of 870 barrels oil equivalent per day in the second quarter. I will now turn to slide 12 and discuss our updated Permian drilling plans for the balance of the year after adding a second horizontal rig. Our new drilling plan targets the drilling of 22 and the completion of 17 horizontal wells in the Midland Basin. This level of activity represents an increase of nine drill wells and five completions over our previous horizontal outlook. Part of this increase was realized in the first half of the year as our team performed more efficiently than originally estimated which will continue to have an impact in the second half of the year with our first horizontal rig. The balance of the increase is coming from the addition of the second horizontal rig for the drilling of four wells in the southern and central Midland Basin. We will be focused on building additional completion capacity in the second half, but have planned for some delay in the production impact from an increased number of drill wells, forecasting associated production coming online in the fourth quarter of 2013 and into early 2014. With the experience we have gained over the last 15 months of horizontal drilling and completion activity and a solid base of infrastructure in place, we believe this is a schedule of activity that can reasonably be achieved with the potential to do even a bit better. I will finish my remarks on slide 13 with a review of the updated operations budget for 2013 which will support the increased pace being realized by our first rig and incremental activity from the second horizontal rig. The budget has been increased by $45 million with the additional expenditures directed exclusively to the horizontal development of our southern and central Midland acreage. For budgeting purposes, we continue to assume an average well cost of $6.5 million for long lateral wells based on our experience at East Bloxom. Let me finish by adding that we have made great strides in positioning our Company for this opportunity in both terms of our Permian footprint and organizational capabilities. We have built a strong team that is focused on execution of the Permian growth opportunity in front of us with a particular focus on enhancing our infrastructure capacity to further accelerate development. I will now turn the call over to Bob Weatherly, our Executive Vice President and CFO. -------------------------------------------------------------------------------- Bob Weatherly, Callon Petroleum Company - EVP and CFO [6] -------------------------------------------------------------------------------- Thank you, Gary. I will now use slide 15 to discuss operational results for the second quarter of 2013 as reported in yesterday's earnings release. In terms of production, you could see the continued growth in our volumes in the Permian Basin growing 20% on a sequential basis. While the sale of Habanero in December of 2012 did reduce our overall production volumes, the redeployment of these proceeds into the Permian has positioned the Company for repeatable sequential production growth as the Permian is firmly established as the main source of production for Callon. I'll now discuss production and realized pricing in some detail. Starting with oil, which represents 60% of our total production and in the second quarter in 2013, production decreased 11% from the second quarter of 2012. This decrease was primarily attributable to the sale of our deepwater Habanero field. Habanero produced 31,000 barrels of oil during the second quarter of 2012 before it was sold in the fourth quarter. Also contributing to the decrease was 23 days of downtime at our Medusa field for scheduled pipeline maintenance which Gary just discussed. Additionally, normal and expected declines further reduced oil production. Partially offsetting these decreases in production from our Gulf of Mexico and other properties, was a 21,000 barrel increase in production from our Permian properties in the second quarter. In terms of pricing, the average price realized for our crude oil volumes for the quarter decreased to $96.27 per barrel compared to $98.78 for the same period 2012. Net of transportation costs, the realized price in the quarter represented a $2.52 premium to NYMEX benchmark reflecting the premium received for our offshore oil volumes partially offset by the discount received for our Permian Basin oil volumes. It should be noted that we have recently experienced a decrease in the premium we received for our offshore volumes relative to WTI Cushing benchmark as bottlenecks in the US pipeline infrastructure have been addressed and WTI prices have reconnected to global crude benchmarks. Compared to the second quarter of 2012, natural gas volumes decreased 13%, once again primarily due to the sale of Habanero from which we produced 52 million cubic feet of natural gas during the second quarter of 2012 and due to a decline in production from our Haynesville well which produced 66 million cubic feet during the second quarter of 2013 compared to the same quarter of 2012. Other normal and expected declines, primarily from our Gulf of Mexico shelf properties, also produced overall production lower. These production decreases were partially offset by a 45 million cubic feet increase from our Permian properties and by a 72 million cubic feet increase from our East Cam 257 field which returned to production in May 2013. The average realized price for natural gas increased 29% to $4.70 per Mcf compared to an average realized price of $3.65 per Mcf in 2012. Our realized natural gas prices on 1 million BTU equivalent basis exceeded NYMEX prices primarily due to the value of the NGLs in our natural gas stream from our Permian Basin and deepwater production. Slide 16 details our financial results for the quarter. Operating revenues for the three months ended June 30, 2013, include oil and natural gas sales of $22.8 million from average production of 3,615 BOE per day. These results compare with oil and natural gas prices of $25.4 million from an average production of 4,110 BOE per day during the comparable 2012 period. Crude oil revenues decreased 14% to $19.1 million for the three months ended June 30, 2013, compared to $22.1 million for the same period 2012. Contributing to decrease in crude oil revenue was a 3% decrease in commodity prices compounded by an 11% decrease in production. Natural gas revenues of $3.7 million increased 13% during the three months ended June 30 as compared to natural gas revenues of $3.3 million for the same period of 2012. The increase primarily relates to a 29% increase in the average price realized partially offset by the previously discussed 13% decrease in natural gas production. For the three months ended June 30, 2013, the Company reported net income of $78,000 or essentially break even for the quarter compared to net income of $3.8 million and $0.09 of diluted earnings per share for the same period 2012. Excluding the after tax gains related to the unrealized mark-to-market derivative adjustments, Callon reported a net loss of $700,000 and a loss per share of $0.02 for the second quarter 2013. Discretionary cash flow for the three months ended June 30, 2013 totaled $10.3 million compared to $12.3 million during the comparable prior year period. Net cash flow provided by operating activities, as defined by US GAAP, was $7.4 million for the three months ended June 30, 2013, and $17.1 million for the comparable prior year period. Moving to slide 17, which summarizes our expenses for the quarter and shows a comparison relative to guidance. Importantly, all of our operational and G&A expenses were in line with or below guidance estimates while production was above our guidance estimates. In terms of operating expenses, our LOE in the Permian Basin, excluding workovers, was $13.26 per BOE for the second quarter. This represents a 12% decrease from the first quarter of 2013. I would also like to note one additional income statement item. Our effective tax rate of 46% for the second quarter 2013 was elevated due to the treatment of certain discrete items including short fall with associates with restricted stock awards that vested during the period. However, we expect our full year effective tax rate to be 30%, excluding any discrete items. Slide 18 depicts our current financial position which was recently strengthened with the issuance of $75 million of perpetual preferred stock. At June 30, our total debt to book capitalization stood at 26%, and our PV10 value at year-end 2012 covered our net debt by a factor of 3. This long term capital strength is complemented by a liquidity position of approximately $88 million at the end of the second quarter. Taken as a whole, we are well positioned to fund the increased level of drilling activity while also pursuing selective acquisitions similar to the Garrison Draw transaction. As we look into the coming quarters, we believe our financial flexibility will continue to improve as our PDP growth continues to drive the level of borrowing base under our senior secured bank facility. As mentioned earlier, we estimate our PDP reserves in the Permian will grow to over 7.5 million barrels of oil equivalent by year-end from just over 3 million barrels of oil equivalent that we entered the year. In addition, a potential sale of our Medusa property would not only represent a significant strategic transaction to the Company, it would be a catalyst to recapitalize our balance sheet with the cost of capital more appropriate for a Permian growth company. Moving to slide 19, I'll take a minute to discuss guidance for the third quarter and full year 2013. We project a total Company production rate for the third quarter to be 4,100 to 4,400 and for the full year to be 4,000 to 4,300 BOE per day with oil accounting for 62% and 65% of these volumes, respectively. In addition, we expect production from our Permian assets to be 2,200 to 2,500 BOE per day for the third quarter, representing a 26% sequential increase over the second quarter using the midpoint of guidance. For 2013, we currently estimate Permian production volumes of 2,200 to 2,400 BOE per day for the full year. The midpoint of our 2013 guidance would represent a 42% increase over full year 2012 production in the Permian. Please refer to our guidance press release which provides additional details regarding guidance for these periods in 2013. This guidance will also be posted on our website in the investor section. Thank you for your attention. Now we'll open the call for questions. ================================================================================ Questions and Answers -------------------------------------------------------------------------------- Operator [1] -------------------------------------------------------------------------------- Thank you. We will now begin the question-and-answer session. (Operator Instructions) Our first question is from Will Green with Stephens. Go ahead, please. -------------------------------------------------------------------------------- Will Green, Stephens Inc. - Analyst [2] -------------------------------------------------------------------------------- I wonder if we could talk about the lower Spraberry for a minute. When do you guys think you might try and put a test into that zone and where do you guys think that presents the best target? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [3] -------------------------------------------------------------------------------- Yes, Will, this is Gary. And we're pretty excited about some of the work that's been going on in the industry, in and around the central Midland Basin, and we certainly think that that opportunity exists for us as we look at the basin across the area that is currently being reported by others. We are looking at the oil in place in the wells that we have with the log data that we have. The thicknesses that we have that would certainly support targeting a significant oil and base target, and we don't have any plans this year to actually ourselves drill a well. We're keenly, keenly focused and have our ear to the ground on all the industry activity in the central Midland Basin. So we're pretty excited about it. -------------------------------------------------------------------------------- Will Green, Stephens Inc. - Analyst [4] -------------------------------------------------------------------------------- Are you guys seeing much industry activity into the Spraberry in the southern part yet and do you anticipate that that could be a target down there? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [5] -------------------------------------------------------------------------------- Yes. Yes, Will, I guess to answer your question directly, we see the potential for it. We haven't seen -- we haven't seen or perhaps haven't heard of yet surrounding industry activity around our leases. And frankly, I've got a lot of good inventory to drill myself just focusing on Wolfcamp A, Wolfcamp B, the lower Wolfcamp B, now we've proven up at Taylor Draw. I'm perfectly happy to have the industry prove that up for me. So we'll continue to keep our ear to the ground, but we're not aware of much work in the Spraberry directly around our southern Midland properties at this point in time. -------------------------------------------------------------------------------- Will Green, Stephens Inc. - Analyst [6] -------------------------------------------------------------------------------- Sure. You guys definitely have a lot on your plate. I was just curious as to what you guys were seeing there, but that's great color. And then, the last one that I had is on as we move into '14, you guys obviously will have the two rigs going. Do you guys have any best guess as to what a good estimate for us to use is for a rig? What that is able to drill per year or per month? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [7] -------------------------------------------------------------------------------- Yes. Will, I would say we're certainly continuing to improve our efficiency everyday and I have great hopes that my team will continue to focus from well to well and improve upon the drilling, but also in the way we can improve our cycle time to finish the completion once we get our infrastructure fully built out. But I would suggest a conservative number would probably be 13 to 14 wells per rig year. -------------------------------------------------------------------------------- Will Green, Stephens Inc. - Analyst [8] -------------------------------------------------------------------------------- Well, that's still a lot of drilling. Congrats on the successes, guys. That's all I had. -------------------------------------------------------------------------------- Operator [9] -------------------------------------------------------------------------------- Our next question is from Ryan Oatman with SunTrust. Go ahead, please. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [10] -------------------------------------------------------------------------------- Thanks. Good morning. Wanted to talk about this acquisition. How did this come about and do you anticipate results, probably similar to the rest of your southern Midland Basin program? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [11] -------------------------------------------------------------------------------- Ryan, essentially the way it comes about, we've got a new team focused on new opportunities and they're always talking to other players, other folks that are either looking at trading or swapping or selling acreage. Through some of those contacts that we've established over time, we got word that there was some acreage that potentially could be available. We made the call, discussed options on valuation, and were able to secure that acreage at a very reasonable acquisition price. We're excited about it because it's in a really good zip code. It's in right there in Reagan County, primarily directly between our exceptional development at East Bloxom and what we see is a really good development at Taylor Draw. So we feel pretty good about it and we're glad to have at least worked over the last couple of years developing the right relationships with other parties in the basin for that to come our way. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [12] -------------------------------------------------------------------------------- Great. And then any leasehold expiration or NRI issues that we should be aware of on that acreage? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [13] -------------------------------------------------------------------------------- No. Certainly drilling the horizontal well there is going to give us a lot of momentum for that acreage. It's actually meeting the leasehold obligations that we see in the near term. So we're in pretty good shape and frankly, we'll be looking to even try to figure out how to weight the leverage ourselves into some more of it. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [14] -------------------------------------------------------------------------------- Great. And then wanted to talk just a little bit up north. I know you guys were doing a little bit of remediation work on the horizontal wells up there trying to isolate the productive zone. Any update there or should we just expect one with the vertical test upcoming? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [15] -------------------------------------------------------------------------------- Yes, Ryan. In summary, we jumped into Borden County thinking we knew how to do that pretty quick. We drilled two horizontal wells, one to the Cline, one to the Miss. Neither one of those worked out unfortunately for us, but we still believe there's a significant oil in place target there in the Miss and this vertical well is going to tell us or at least validate what we believe to be our development model there. There's two schemes there. One is truly a lot of oil in place in some matrix porosity in the Miss, and there's another scheme around a lot of oil in a place in a targeted high porosity chat zone. So we're going to test both of those theories and then we'll be able to say how we would go about further development of that area after we talk about this -- as we get this vertical well done and do some really some isolated testing in a specific spot in the Miss, and I think it's the right way to go. We've got a large position there. We've got a large oil in place target and we'll be able to balance that development with everything else we've got going on in the central and southern Midland Basin. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [16] -------------------------------------------------------------------------------- Very good. And then one final one for me before I hop back in the queue. I notice you guys had delineated some Cline acreage as potentially prospective. Where specifically was that? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [17] -------------------------------------------------------------------------------- Ryan, that's primarily in the southern Midland Basin, primarily in the areas that -- of our new acquisition as well as the Taylor Draw area, pretty much just south of the Cline development just to the north. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [18] -------------------------------------------------------------------------------- Great. That's it for me right now. Thank you. -------------------------------------------------------------------------------- Operator [19] -------------------------------------------------------------------------------- Our next question is from Gabriel Daoud with Sidoti & Company. Go ahead, please. -------------------------------------------------------------------------------- Gabriel Daoud, Sidoti & Company - Analyst [20] -------------------------------------------------------------------------------- Good morning, guys. Just I guess the first question from me is when can we expect results from the next wave of horizontals? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [21] -------------------------------------------------------------------------------- As we said in the presentation, we've got several wells in process right now, but we are just now coming out of a hole on our final drill-out for the four-well pad at Taylor Draw. So as we get that well buttoned up, we'll be ready to bring really four wells on in the next couple of weeks. That's how far along we are with the next wave of wells. We feel pretty good about the wells themselves. We'll have to flow them for 30 to 35 days before we get actually as you guys are well connected to those required Railroad Commission reports, I think that's probably when you'll see that last next date is we routinely start to reporting those completion rates and 30-day rates through the Railroad Commission. So I'd say in 30 to 45 days, you should see more reports coming through the Railroad Commission. -------------------------------------------------------------------------------- Gabriel Daoud, Sidoti & Company - Analyst [22] -------------------------------------------------------------------------------- Okay, great. And I guess next question, in terms of Midland County and the horizontal program there, when do you guys expect to move the new rig there to begin drilling horizontals? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [23] -------------------------------------------------------------------------------- Yes, again we're just getting started. We just spud this morning on the first well on our Garrison Draw properties. That's going to be a little -- about a 7,500-8,000-foot horizontal well and as soon as we're finished with that, in really less than 30 days, we'll be moving up to our Carpe Diem field in the central Midland Basin. So we'll be there shortly. -------------------------------------------------------------------------------- Gabriel Daoud, Sidoti & Company - Analyst [24] -------------------------------------------------------------------------------- Okay, great. And then just one more guys, if I could. If you can maybe provide some updated commentary on the Medusa asset and how the marketing efforts are coming along. -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman and CEO [25] -------------------------------------------------------------------------------- The marketing is continuing and we continue to have good interest and I think we're on track. As we had I think said earlier, I think we're targeting the fourth quarter to hopefully have an offer that's acceptable that we could close by year-end, but the short answer is yes, we're continuing our market efforts. We're having good interest. We're having meetings and kind of we feel like we're still on track to be seeing offers and hopefully making a decision by the fourth quarter. -------------------------------------------------------------------------------- Gabriel Daoud, Sidoti & Company - Analyst [26] -------------------------------------------------------------------------------- All right, great. Well, thanks, Fred. Thanks, guys. Thanks for the time. -------------------------------------------------------------------------------- Operator [27] -------------------------------------------------------------------------------- Our next question is from Tim Rezvan with Sterne, Agee. Go ahead, please. -------------------------------------------------------------------------------- Tim Rezvan, Sterne, Agee & Leach, Inc. - Analyst [28] -------------------------------------------------------------------------------- Good morning, folks. Some of my questions have been answered, but I just have one. With this new acreage tuck-in done, what is your app? I mean, obviously you're signaling that you're interesting in bolting on more. Is there kind of a budget that you have that you think you can -- is there an acquisition budget in place? How big do you think you can get in terms of spending? -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman and CEO [29] -------------------------------------------------------------------------------- Well, I think as a general rule, we don't budget for acquisitions and I think the -- we continue to look for opportunities like the acquisition down at Garrison Draw, bolt-on type acquisitions which could be -- they're smaller, but they can be very meaningful to us and particularly if they're in the areas that we're currently active operating. So we're continuing to look for what I would say smaller opportunities like that. At the same time, we continue to look at perhaps a larger more meaningful acquisition. In that case, I think some of the properties that we'd carry production with them that would have a larger PDP component and so we continue to look for opportunities like that and hopeful that we'll be able to find one to execute on, at some point, but I'd say certainly focus is the smaller bolt-on acquisitions, don't have a budget necessarily. As Gary mentioned earlier, we've got a pretty good sized inventory here and with -- we think up to 10 years of drilling right now with a two rig program, we don't feel compelled to add acreage immediately, but we're continuing and actively looking to continue to add to the inventory. -------------------------------------------------------------------------------- Tim Rezvan, Sterne, Agee & Leach, Inc. - Analyst [30] -------------------------------------------------------------------------------- Okay. Thanks. I appreciate that color. And then just one more for me. On the new assets, how many locations are you including when you talk about the run rate you have? How many horizontal locations in Garrison Draw? -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman and CEO [31] -------------------------------------------------------------------------------- Garrison Draw. We've got a pretty good core position there that gives us multiple wells across the area and if you then compound that with the multiple benches that we have, you're well over 20 or so or even 30 or so wells. So it will add up pretty quick. -------------------------------------------------------------------------------- Tim Rezvan, Sterne, Agee & Leach, Inc. - Analyst [32] -------------------------------------------------------------------------------- Okay. Thanks, folks. -------------------------------------------------------------------------------- Operator [33] -------------------------------------------------------------------------------- The next question is from Jeb Bachmann with Howard Weil. Go ahead, please. -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil - Analyst [34] -------------------------------------------------------------------------------- Gary, just a couple questions on those deep Wolfberry wells and if you could provide some color on the cost and EUR assumptions you think you could get out of those wells going forward. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [35] -------------------------------------------------------------------------------- Yes. We feel pretty good about those wells you're talking about, the deep Wolfberry level -- [I'm sorry, deep Wolfberry combination] of Carpe Diem and Pecan acreage and the -- -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil - Analyst [36] -------------------------------------------------------------------------------- Right. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [37] -------------------------------------------------------------------------------- Yes. Okay. The cost of the well is about $2.9 million to $3 million completed cost and there's -- we're looking at multiple zones, multiple stages in the frac. The last 23 -- number 23-11 well was 12 stages throughout that whole section and early time, we're certainly exceeding our type curve for that area of around 150 MBOE wells. We haven't really increased that type curve yet for the wells we have simply because we're so new into the play, but I would expect that to be approaching 200 in BOE wells over time. Again, it's early time, so my engineers aren't pushing me on that level yet, but I'm guessing between 150 and 200. -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil - Analyst [38] -------------------------------------------------------------------------------- Okay, great. And then looking at the Garrison Draw, what kind of well density or well control do you have on those -- on that acreage when you bought it, I noticed with the small amount of production? Is that all vertical wells that have been producing there? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [39] -------------------------------------------------------------------------------- Yes, that is all vertical production that we have there, and what we really were looking for, for the opportunity was building a position that could also have not only vertical potential but also significant horizontal growth opportunity and that's primarily the reason we got it and frankly, we're drilling the well right now. We just spud it and we should have results rather shortly about how prospective that area is and certainly all around, there's been pretty good results from horizontal development in the area. -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil - Analyst [40] -------------------------------------------------------------------------------- All right. Then last one for me for Bob, looking at production guidance for this year, am I looking at this correctly? 65% average would imply an exit rate or a 4Q average 68% to 70% on the oil weighting? -------------------------------------------------------------------------------- Bob Weatherly, Callon Petroleum Company - EVP and CFO [41] -------------------------------------------------------------------------------- Yes. That is pretty close. -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil - Analyst [42] -------------------------------------------------------------------------------- And is that what you guys think going forward now with the ramped up Permian program? -------------------------------------------------------------------------------- Bob Weatherly, Callon Petroleum Company - EVP and CFO [43] -------------------------------------------------------------------------------- I don't know that we're looking quite that high going forward, depending on how much gas component we get. -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil - Analyst [44] -------------------------------------------------------------------------------- Okay. Thanks, guys, appreciate it. -------------------------------------------------------------------------------- Operator [45] -------------------------------------------------------------------------------- The next question is from Trevor Menke with Robert W. Baird. Go ahead, please. -------------------------------------------------------------------------------- Hsulin Peng, Robert W. Baird & Company, Inc. - Analyst [46] -------------------------------------------------------------------------------- Good morning. This is actually Hsulin. Great quarter. Congratulations and I guess my -- sorry if I missed this. My first question is regarding your exit rate for 2014 in the Permian. Is that based on assumption of running two rigs flat through 2014? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [47] -------------------------------------------------------------------------------- Yes. -------------------------------------------------------------------------------- Hsulin Peng, Robert W. Baird & Company, Inc. - Analyst [48] -------------------------------------------------------------------------------- Okay. Okay, that's fine. And then like you say, your assumption has been sort of 13 to 14 per well per rig per year, so the run rate roughly? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [49] -------------------------------------------------------------------------------- Yes. Hsulin. We'll be doing 13 to 14 wells per rig year. So two rigs is 26 wells, 27 wells. So that's certainly doable with the opportunity and the efficiency that we're demonstrating today and certainly getting far more efficient with bringing those wells on with our infrastructure buildout for the first half of this year and for the last half of 2013. So that's certainly a doable schedule. -------------------------------------------------------------------------------- Hsulin Peng, Robert W. Baird & Company, Inc. - Analyst [50] -------------------------------------------------------------------------------- Okay. And then I know last time you guys talk about batch completion, so I'm just wondering how many wells are you drilling per pad in the area and how many wells are you completing each time and what kind of cost savings and also current well costs are you looking at? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [51] -------------------------------------------------------------------------------- Hsulin, up to this point we've been targeting three wells per pad and, of course, the significant savings comes in because the type of rig we have, we can move that rig from one well to the next well really in less than 24 hours now. We've gotten very efficient with that. We can leverage all the services, all the costs for one well over three. We can improve our overall timing just by getting good at what we do for each one of those pads. If we're shaving off a day, we're saving money. And then importantly, as we get fully capable with our planned infrastructure buildout, we'll be able to move well to well to well back to back to back to back as we frac those wells. So the most we've ever drilled from one pad is four wells and that's the four wells that are coming on in the next week or so at Taylor Draw. So what we anticipated and what we knew kind of would happen is happening and what others are starting to realize is they go into the pad development, is we need to have significant infrastructure to be able to efficiently bring those wells on after we get them drilled and that's what we've been focused on in the first half of this year and certainly continue to focus on in the second half of this year is making certain that that infrastructure is there so that we can minimize actually the amount of production shut-in time for all those wells as we efficiently complete all the wells on a given pad. So we're getting better at that and again, that's kind of part of the reason our ramp is kind of deferred to the last half of '13 and early into '14 as we continue to build out that infrastructure. Hopefully you find that helpful. -------------------------------------------------------------------------------- Hsulin Peng, Robert W. Baird & Company, Inc. - Analyst [52] -------------------------------------------------------------------------------- Right. And so can you just tell us what the well cost is currently? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [53] -------------------------------------------------------------------------------- Yes. Our current cost is about $6.5 million for a 7,500-foot well. It will be less than that for a 5,000-foot well, but $6.5 million we've been repeatedly doing that. That's the reason we quickly went into development mode. We knew cost was very, very important even though we knew that that would cause somewhat of a delay simply because of the chunkiness of our production as it comes on from pad to pad in our overall ramp-up, but we felt that was the right way to go. -------------------------------------------------------------------------------- Hsulin Peng, Robert W. Baird & Company, Inc. - Analyst [54] -------------------------------------------------------------------------------- Okay. That makes sense. And then last question is just the third vertical in the north in Midland well, in the northern Midland area, so it sounds like you are targeting the Miss interval. When do you think you'll know -- when do you expect to have the results and are you seeing any near activities that you can learn from? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [55] -------------------------------------------------------------------------------- Yes. Hsulin. I just want to make sure we're talking about the right well. We talked about deeper potential in the central Midland Basin and that's what Pecan Acres number 23-11 demonstrated. We've got the other well that we didn't specifically talk about in our discussion earlier was the Pecan Acres 22-C1 which would be another well that's been drilled deep and is now currently coming on and ramping up nicely. Then the other two wells we talked about deeper potential from a vertical sense were in Carpe Diem field and we've got those two wells drilled. In fact, we're fracking one of those wells as we speak today and all that potential is in the central Midland Basin, around Pecan Acres and Carpe Diem. Was that the genesis for your question or did you have some other question? -------------------------------------------------------------------------------- Hsulin Peng, Robert W. Baird & Company, Inc. - Analyst [56] -------------------------------------------------------------------------------- Actually, I was asking about the vertical well in the north Midland. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [57] -------------------------------------------------------------------------------- Okay. Yes, okay. I got you. So the well that actually that we completed already. We completed a well in northern Midland Basin. It was one of our vertical test wells when we first started. It had three zones in it, one in the Wolfcamp, one in the Spraberry, one in the Clear Fork that we fracture stimulated and we're currently flowing that well back as we speak and we don't have quite enough recovery from that well to fully define what it's going to do. So that well is on production and flowing back and then the well we're currently drilling, in fact, we're logging it today, is our vertical test again to further delineate our Mississippian play in that entire acreage position in the northern Midland Basin. -------------------------------------------------------------------------------- Hsulin Peng, Robert W. Baird & Company, Inc. - Analyst [58] -------------------------------------------------------------------------------- Okay. So we don't have results from the one that you're currently -- I mean, when do you think we can get results on the one that you're currently drilling? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [59] -------------------------------------------------------------------------------- The one that we're currently drilling I would guess is going to take us at least two months to fully evaluate that test, Hsulin. We'll have to work that into our development model, fully understand what we'll want to do there and then understand what pace we want to do it to make sure we don't get out ahead of ourselves, frankly like we previously did. So we'll do that in a very measured pace, so. -------------------------------------------------------------------------------- Hsulin Peng, Robert W. Baird & Company, Inc. - Analyst [60] -------------------------------------------------------------------------------- Okay, no. Understood. Okay. Thank you. -------------------------------------------------------------------------------- Operator [61] -------------------------------------------------------------------------------- The next question is from Mike Kelly with Global Hunter Securities. Go ahead, please. -------------------------------------------------------------------------------- Mike Kelly, Global Hunter Securities, LLC - Analyst [62] -------------------------------------------------------------------------------- Thanks, guys. Good morning. Great color on all this activity in the Permian. It's very helpful. If I look at slide 5, you laid out your inventory here and what areas of perspective. Hopefully, we can talk a little bit about what acreage you've risked out of this in terms of this location count here. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [63] -------------------------------------------------------------------------------- I guess what we risked, I just want to describe to how we went about it, you know, to understand what's in it. Certainly, we went through every area, looked at surrounding development within the industry of interesting and exciting reported results. Looked at really our resource under our leases to make certain that our inventory of work and the way we understood the petro-physical analysis of it supported a large target, an oil in place target but appropriate porosity development and reasonable thicknesses to justify a horizontal development program. And that's how we actually got to the point where we further defined really the opportunities set ahead of us. So what out of this inventory, if anywhere we didn't expect to have that porosity develop or thickness and that varies across each of these areas or fields simply based on our called-out various parameters that we chose to use to develop this inventory. For instance, we see limited Cline potential in our East Bloxom field where we see exceptional performance for Wolfcamp A, Wolfcamp B, and even middle Wolfcamp for lower Wolfcamp B development, and we see really limited potential for any of that in our Block 5 field down in Crockett County. So it kind of varies depending on where we are across the basin. Same with Carpe Diem and Pecan Acres. We really haven't targeted any Cline potential up in the central Midland Basin. So it's a bit of a difficult question to answer from a basin-wide perspective, but in summary, we see Cline, lower Wolfcamp, upper Wolfcamp, Wolfcamp A, clearly in the southern Midland Basin acreage that we have to varying degrees, and we would add to that Spraberry, Jo Mill and take away the Cline in our central Midland Basin properties. So hope that helps. -------------------------------------------------------------------------------- Mike Kelly, Global Hunter Securities, LLC - Analyst [64] -------------------------------------------------------------------------------- Yes. That helps. It's safe to say that there's potentially a decent amount of upside here in this location count as industry activity increases and across these various areas? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [65] -------------------------------------------------------------------------------- It is safe to say that and the only other criteria I would put on it, I think, is upside around potential down spacing. Again kind of the way we -- we kind of looked at this rather conservatively was really six wells across the section or close to 140 to 160 acre spacing. We know some companies are testing even down spacing around that. We're already considering adding a seventh well across our acreage in certain areas of the basin. So there is, I would suggest, upside to that number. -------------------------------------------------------------------------------- Mike Kelly, Global Hunter Securities, LLC - Analyst [66] -------------------------------------------------------------------------------- Okay, great. And on the infrastructure side of things here, I just want to make sure for modeling purposes have this understood correctly, you talked about 13, 14 wells per rig. Is the infrastructure going to be completed to the point where the completion count should look pretty similar to that in 2014? Or is there still going to be somewhat of a lag there? Just want to understand that a little bit clearer. Thanks. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [67] -------------------------------------------------------------------------------- I feel fairly confident it's going to be pretty complete by the end of the year. There's always uncertainties around water sourcing in some areas, but I think we're solving that problem as we go. Certainly building the amount of storage capacity necessary to fracture stimulate two or three wells in a given time. We are well on our way to getting that done and well on our way to accessing other reservoirs besides the freshwater, that being the Santa Rosa water wells, and drilling several of those to improve our water source capacity. But by the end of this year, modeling for 2014, I would suggest that we should be able to have the same number of completions as the wells that were drawn. Some of those should carry on over from '13, but that will certainly add up to the same number because then we'll be in a reasonably efficient cycle. -------------------------------------------------------------------------------- Mike Kelly, Global Hunter Securities, LLC - Analyst [68] -------------------------------------------------------------------------------- Great. And then just one more, and I guess this question more for Fred and maybe I was thinking about this wrong probably from day one here. But I always kind of thought of the big critical factor for you guys is the activity in the northern Midland Basin in Borden, but with 10 years plus inventory now on what could be a conservative location count in the southern and central portions of Midland, how reluctant are you to let go of that acreage up north? Or I guess, maybe reverse of that, how willing will you be to potentially depart with that acreage, divest of it, and just stick to the knitting here with some acreage that really looks good in the southern portion of the basin? -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman and CEO [69] -------------------------------------------------------------------------------- Well, from the beginning our focus has been in the southern Midland Basin. That's our legacy properties and that's really where we've been focused in Upton, Reagan, and Midland. I mean, that's where we started with our vertical drilling. That's where we've done most of our work. That's where we initiated our horizontal program. Borden, from the beginning, was an exploration effort as we talked about, we were able to put acreage together up there for -- I can't remember -- $600, $700 an acre. As you'll recall, we were testing the Cline and the Mississippian. We've tested the Cline and at this point, feel like that it's just not fully mature and do not think it's going to be economic. The Mississippian has some energy, continues to have I think two rigs up there and continues to be active. They are immediately to our west and we certainly see the hydrocarbons and the Mississippian and so we think it's a play that we should continue to pursue. If you look at our budget, we're not allocating significant dollars to a horizontal program there yet. We're taking I think our period measured approach. So we'll continue to evaluate that. As Gary mentioned first with this vertical well, we'll do a lot of testing there and based on that, we'll take a look at it and decide if we want to drill a second horizontal well. We do feel like our initial horizontal well, the Mississippian, had a number of operation issues and so we'll continue to evaluate that. So the short answer is, certainly we're focused in the Upton, Reagan, Midland County, that's where our budget's going and we don't plan to expose a significant part of our budget to Borden County unless -- until our continued evaluation, delineation we get to the point where we feel like it's justified. -------------------------------------------------------------------------------- Mike Kelly, Global Hunter Securities, LLC - Analyst [70] -------------------------------------------------------------------------------- All right, great. Appreciate the color. Good luck with that four-well pad. -------------------------------------------------------------------------------- Operator [71] -------------------------------------------------------------------------------- The next question is from Ron Mills with Johnson Rice. Go ahead. -------------------------------------------------------------------------------- Ron Mills, Johnson Rice & Company - Analyst [72] -------------------------------------------------------------------------------- Good morning, guys. There's still one more question. Can you describe for me, Gary, when you talk about the upper Wolfcamp B and lower Wolfcamp B, what you're using as a separator in there? I guess I know the notice nomenclature surround out there? But what's the difference in your mind separating the Wolfcamp base from the upper from the lower Wolfcamp base? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [73] -------------------------------------------------------------------------------- The Wolfcamp B by itself is fairly a thick interval and what we've been targeting is that upper Wolfcamp B bench, a lot of oil in place up there, a nice organic streak around it, but at the end of the day, what we actually looked at and tried to further test is there's another organic rich section about I'd say 400 feet lower, Ron, to give you a vertical difference. And we went ahead and drilled a well to that level just to kind of see how it might perform and then while we were completing it we went ahead and ran micro-seismic to kind of validate our overall assumptions around fracture growth and the well itself is the well that we've been talking about, the Weatherby 1H. It's performing quite nicely, early time. It's got really nice pressure to it. We're pretty excited about the early time performance. Time will tell what it looks like but it's behaving quite nicely and that vertical separation, essentially, was validated that would fit with our micro-seismic analysis. So if that helps you, the Wolfcamp -- upper Wolfcamp B is the upper part, upper 300, 400 feet and then we have this other section that's about 400 feet lower. -------------------------------------------------------------------------------- Ron Mills, Johnson Rice & Company - Analyst [74] -------------------------------------------------------------------------------- Okay. So that just answered my follow-up. I was going to ask what you thought the total thickness was. So you think it's 300 plus or minus feet in what you're calling the upper bench and 400 feet in the lower -- 400 feet below that is in the lower bench. So are you saying that whole zone is 700 feet or did I misunderstand? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [75] -------------------------------------------------------------------------------- Yes. It's a minimum of 700 feet, Ron, and we're not actually going to the very base of that Wolfcamp B when we talk about that lower Wolfcamp B. It's actually not quite to the bottom. -------------------------------------------------------------------------------- Ron Mills, Johnson Rice & Company - Analyst [76] -------------------------------------------------------------------------------- Okay. And then the Wolfcamp B test in this micro-seismic, what you also suggest is the micro-seismic showed that the basin in that area can be two distinct zones you're not communicating. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [77] -------------------------------------------------------------------------------- That's exactly what the micro-seismic showed. It definitively showed that hey, the upper Wolfcamp did not grow into the Wolfcamp A and the lower Wolfcamp B target would not grow into the levels that we completed in the Wolfcamp -- upper Wolfcamp B. So we feel very confident that there's two levels of development in that area, certainly right there at Taylor Draw. We see that same opportunity in our new Garrison Draw properties and potentially even at East Bloxom as we carry that across. And frankly we could actually think about how we would potentially stagger those wells across the vents to minimize the level of influence or level of interference that that might see from each other as we go further with an overall development. So there's lots of things that are working positively in that direction that clearly defines another level of development within the Wolfcamp B zone. -------------------------------------------------------------------------------- Ron Mills, Johnson Rice & Company - Analyst [78] -------------------------------------------------------------------------------- Perfect. And you just answered my final one was where which of your fields you think you have that development. It sounds like it's really kind of across at least parts of all three fields in your southern Midland Basin. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [79] -------------------------------------------------------------------------------- That is correct. -------------------------------------------------------------------------------- Ron Mills, Johnson Rice & Company - Analyst [80] -------------------------------------------------------------------------------- Okay, perfect. Thank you, guys. -------------------------------------------------------------------------------- Operator [81] -------------------------------------------------------------------------------- Our next question is from Philip Dodge with Noble Financial. -------------------------------------------------------------------------------- Philip Dodge, Noble Financial - Analyst [82] -------------------------------------------------------------------------------- Yes, good morning. Appreciate all the good comments. I may be dropping the gun on this question, but I will ask anyway. You're obviously getting acceleration in growth of production by bringing in the second rig in May. Do you have a forecast on how long you can maintain a production incline in the Midland before you have to consider bringing in a third rig? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [83] -------------------------------------------------------------------------------- You might be jumping the gun there a little bit, but I would suggest that we should be able to grow production throughout 2014 before the growth in production then starts offsetting or the decline in our existing production base starts offsetting our added contribution from new wells. In other words, the -- -------------------------------------------------------------------------------- Philip Dodge, Noble Financial - Analyst [84] -------------------------------------------------------------------------------- That's what I was wondering about, visibility for another year and a half or so or greater visibility? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [85] -------------------------------------------------------------------------------- Yes. Certainly throughout '14, I'd feel comfortable saying that and so -- and, gosh, and I only say that because I'm still using a type curve that I think can now perform. So as I look out at what could be happening, I could see growth well beyond '14. So pretty premature. I agree with your first comment, you're a little premature with that. But, we'll -- -------------------------------------------------------------------------------- Philip Dodge, Noble Financial - Analyst [86] -------------------------------------------------------------------------------- I'll wait a while before I ask it again. (laughter) Okay. Thanks a lot. -------------------------------------------------------------------------------- Operator [87] -------------------------------------------------------------------------------- Our next question is from Adrian Fekula with Brean Capital. Go ahead, please. -------------------------------------------------------------------------------- Adrian Fekula, Brean Capital - Analyst [88] -------------------------------------------------------------------------------- Yes. Good morning, everybody. This is Adrian filling in for Jeff. I just have a few questions really quick about the two Neal wells that you guys talked about this morning. You had the decline rate between the 24 hour and the 30 day production rate seems a bit high. What do you think is causing the variability in rates? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [89] -------------------------------------------------------------------------------- No. I think actually you're going to see variability across the basin, not just in our Neal wells. I think you can look at 24 hour IPs and 30 day rates, those are very reasonable and probably very common across the entire basin. Once we get the -- our fracs to come back, these wells take off pretty strong and then they decline hyperbolically fairly quickly over that first month or two period before they start stabilizing and I just think that's the nature generally of what many of the wells in the basin are doing, even at these 450 to 500 MBOE type curves. Now there will be the exception and that would be the well that holds in there for an extended period of time and we recently heard about several of those from the different companies. But I think this is normal and natural and it's customary type of decline. -------------------------------------------------------------------------------- Adrian Fekula, Brean Capital - Analyst [90] -------------------------------------------------------------------------------- Okay, great. Thanks. And number two, on some of the older horizontal Wolfcamp wells, do you have any data points on 60 or 90 day production rates that you could share with us right now and how are those performing against your type curve? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [91] -------------------------------------------------------------------------------- Oh, gosh, Adrian, I got to be honest with you. I can look at the overall longer term components of those wells and I'm pretty excited about the 321 well, the first well we brought online is still producing well over 200 to 300 barrels of oil equivalent per day. So I feel good about those wells in the near term, but I stay focused on what's coming, what's coming next and executing on the plan in an efficient way. So I frankly haven't done that math. I apologize. -------------------------------------------------------------------------------- Adrian Fekula, Brean Capital - Analyst [92] -------------------------------------------------------------------------------- All right. That's fine. Thank you very much. -------------------------------------------------------------------------------- Operator [93] -------------------------------------------------------------------------------- The next question is a follow-up from Ryan Oatman with SunTrust. Go ahead, please. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [94] -------------------------------------------------------------------------------- Thanks. And indeed it is. I'll keep it very short here. What is your working interest kind of on average across the wells? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [95] -------------------------------------------------------------------------------- Gosh, I guess on average I don't know that number, but I would say it's 90%-plus working interest across the southern and central Midland Basin and Permian fields, but yes, it's around that number. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [96] -------------------------------------------------------------------------------- Perfect, and then I just missed it. I wanted to confirm that deep Wolfberry, what was that vertical cost on that vertical deep Wolfberry? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [97] -------------------------------------------------------------------------------- $3 million. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [98] -------------------------------------------------------------------------------- $3 million. Great, thank you. -------------------------------------------------------------------------------- Operator [99] -------------------------------------------------------------------------------- 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 Callon, Callon Petroleum Company - Chairman and CEO [100] -------------------------------------------------------------------------------- Again, we appreciate everyone taking time to call in and in the meantime if anyone has any questions, please do not hesitate to give us a call. Thank you. -------------------------------------------------------------------------------- Operator [101] -------------------------------------------------------------------------------- The conference is now concluded. Thank you for attending today's presentation. Please disconnect your lines.
|