NATCHEZ Aug 6, 2015 (Thomson StreetEvents) -- Edited Transcript of Callon Petroleum Co earnings conference call or presentation Thursday, August 6, 2015 at 1:00:00pm GMT TEXT version of Transcript ================================================================================ Conference Call Participants ================================================================================ * Eric Williams Callon Petroleum Company - Manager of Finance * Fred Callon Callon Petroleum Company - Chairman, President and CEO * Gary Newberry Callon Petroleum Company - SVP of Operations * Joe Gatto Callon Petroleum Company - SVP, CFO and Treasurer * Will Green Stephens Inc. - Analyst * Jeb Bachmann Howard Weil Incorporated - Analyst * Ron Mills Johnson Rice & Company - Analyst * Irene Haas Wunderlich Securities, Inc. - Analyst * Neal Wheatly SunTrust Robinson Humphrey - Analyst * Ipsit Mohanty GMP Securities - Analyst * Ryan Oatman SunTrust Robinson Humphrey - Analyst * Mo Dahhane Northland Securities, Inc. - Analyst * Phillips Johnston Capital One Southcoast, Inc. - Analyst ================================================================================ Presentation -------------------------------------------------------------------------------- Operator [1] -------------------------------------------------------------------------------- Good day, and welcome to the Callon Petroleum Company's second-quarter financial and operating results conference call. All participants will be in listen-only mode. As a reminder, this call is being recorded. A replay of the call will be archived on the Company's website for approximately one year. I would now like to turn the call over to Eric Williams, Manager of Finance, for opening remarks. Please go ahead, sir. -------------------------------------------------------------------------------- Eric Williams, Callon Petroleum Company - Manager of Finance [2] -------------------------------------------------------------------------------- Thank you. Good morning, and thank you for taking time to join our second-quarter 2015 results conference call. With me this morning are Fred Callon, Chairman and CEO; Gary Newberry, Senior Vice President of Operation; and Joe Gatto, Senior Vice President, Chief Financial Officer and Treasurer. During our prepared remarks we will be referencing the earnings results presentation we posted yesterday afternoon to our website, so I encourage everyone to download the presentation if you haven't done so already. You can find the slides on our website at www.Callon.com. To locate the slides, simply click the PDF icon located on the events and presentations page for today's conference call or, alternatively, click the current presentations link included at the bottom of any page on our website. Before we began I would like to remind everyone joining this call that our comments today include forward-looking statements. A variety of factors could cause Callon's actual results to differ materially from the anticipated results or expectations expressed in these forward-looking statements. For a complete discussion of these risks, we encourage you to read our filings with the SEC including our Form 10-K available on our website or the SEC's website. Today's call will also contain discussions of certain non-GAAP financial measures. Please refer to the earnings press release we issued yesterday afternoon for important disclosures regarding such measures and the corresponding reconciliations. You can obtain a copy of our press release in the news section of our website. After our prepared remarks we will be happy to take your questions. And with that I would like to turn the call over to Fred Callon and direct the audience to slide 3 of the earnings presentation I referenced. Fred? -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman, President and CEO [3] -------------------------------------------------------------------------------- Thank you, Erik. And once again, thank you, everyone, for joining us this morning. We are very pleased to report another solid overall quarter for the Company, demonstrating our ability to reduce capital expenditures, delivering sequential production growth and strong cash margins. Production in the quarter averaged just over 9,500 barrels of oil equivalent per day, which is an 11% increase over the first quarter of 2015. As you recall, entering the second quarter we dialed back our drilling pace to 2 horizontal rigs to produce our CapEx spend through an uncertain commodity price environment and maintain flexibility. Despite the earlier run-up in crude oil prices to low $60s, we remain committed to a longer-term view of the business and deferred a decision on incremental drilling activity until we have a better picture of our operating cost structure in the current price environment and better visibility on our goal of self-funding our operational plan. Now having observed and the recent double dip in oil prices, our approach to planning has not changed as we look to the future. We've built a focused, disciplined Company that we expect to generate resilient cash margins and continued production growth, allowing us to manage through volatility and progress to cash flow neutrality. Our EBITDA margin was 70% during the past quarter, which benefited from a 32% reduction in lease operating expense per BOE since the fourth quarter of 2014 and a continued decrease in our per-barrel G&A cost as we remain focused on our corporate cost structure while continuing to meaningfully grow production. From a capital standpoint, our capital expenditures dropped 20% from the first quarter as we realized the impact of decreasing well cost in a slower pace of completions. We are currently budgeting for 7,500-foot laterals approximately $6 million, which reflects both cost savings in a current environment and operational efficiencies captured by our team. In addition, this well cost figure also includes costs related to enhanced completion designs that Gary will discuss in more detail in a few minutes. While we are committed to reducing capital costs as much as possible, we are also looking for ways to improve overall resource recoveries if the marginal dollars spent delivers incremental returns. On the financial side, our liquidity position currently stands at over $175 million against an estimated quarterly run rate CapEx program of approximately $30 million to $35 million for the foreseeable future, based on current well costs. We view this level of current liquidity as a valuable asset but also remain focused on our goal of becoming self-funding by mid next year. Although we began talking about this target before the recent pullback in oil prices, we believe it is still achievable based on our updated production estimates for 2015 and 2016, which we have now increased to midpoints of 9,600 barrels of oil a day and 11,750 barrels of oil a day in 2016. This financial goal is important for two reasons. First, it removes our reliance on outside capital in an environment that is prone to heightened volatility. Second, it positions us to be opportunistic to pursue both organic and non-organic growth opportunities. As we look out over the next several quarters we realize that our industry faces a number of challenges. However, we believe that we are well-positioned in the best basin with a strong asset base, very capable, efficient organization that allow us to thrive in a new environment and to capitalize on opportunities to grow our presence in the Permian. I will now ask Gary Newberry, our Senior Vice President of Operations, to discuss our operating results for the quarter. Gary? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [4] -------------------------------------------------------------------------------- Thanks, Fred, and good morning. I'll start on slide 4 with a brief operational update and a summary of our activity in the second quarter. We drilled 9 gross wells and completed 8 gross wells in the second quarter, relative to 10 gross wells drilled and 11 gross wells completed in the first quarter. As we enter the third quarter we expect our pace under a normalized 2-rig drilling and completion program to be approximately 6 to 7 completions per quarter going forward. Our activity continues to be focused in the core area of the Central and Southern Midland Basin, shown in the darker green area on the maps. We are now producing from 4 zones at our East Bloxom field and 3 zones at Garrison Draw in the southern area. In the central region, we have established production from 2 zones in each of our three fields, including our first 2-well pad in the Pecan Acres field. In the near term, we plan to defer our development plans at Taylor Draw as we monitor the impact of the new completion concepts that we and offsetting operators are using in both the Wolfcamp A and Wolfcamp B to improve returns in the shallower part of the basin. Slide 5 highlights (technical difficulty) results compared to our latest announced type curves in two areas of focus that will complement our legacy Wolfcamp B programs at the East Bloxom field and in our Central Midland Basin position. Both of these areas have been well-established, with 36 wells drilled and completed over the past few years. On the left-hand side, we provide a summary of our Central Basin Lower Spraberry results to date, all of which are outperforming our 912,000 BOE type curves. Similarly, the right-hand chart highlights our recent Wolfcamp B well results in the Garrison Draw field, which is a key driver of our outperformance relative to the last two quarters of production guidance. In addition to the contribution from this field, our increased capital allocation to the Lower Spraberry in future quarters provides a meaningful uplift to our production outlook for 2016 and beyond. While we are primarily in block-and-tackle mode across our core plays, we continue to selectively delineate new zones and implement multi-zone development concepts. Slide 6 details our recent progress on these fronts, including recent production data from our first stacked well test of the Lower Spraberry and Wolfcamp B at Pecan Acres in Midland County. These wells both produced at 30-day, two-stream rates of approximately 190 barrels of oil equivalent per day per 1,000 lateral feet, which is at the top of industry results. We see this as another encouraging data point for the future potential of our Central Midland position. We've also progressed our activity beyond the Wolfcamp B in the Southern region, which recently targeting both the Wolfcamp A and Lower Spraberry. In terms of the Wolfcamp A, our recent well at Taylor Draw continues to clean up and increase its oil rate as it de-waters. While this well only brings our total Wolfcamp A well count to 4 in the region, the extended well performance we've seen at Garrison Draw and East Bloxom has been a positive with average 30-day rates of 800 barrels of oil equivalent per day in our last 2 wells. We are also encouraged by the steady increase in Wolfcamp A drilling activity in Reagan County that have also used larger proppant concentrations and testing new landing points. Staying in the Southern Midland area, we continue to monitor the performance of the Lower Spraberry pilot well in Upton County, which has been on production since late February of this year. Production response has been delayed as we initially completed the well with gas lifts, which did not provide adequate drawdown for the lower pressures at Lower Spraberry formation. We then shut the well in to perform a significant tank battery upgrade to improve our gas handling and sales capability. After bringing the well online with ESP, we are very encouraged with the peak 24-hour, two-stream rates of 788 barrels of oil equivalent per day with almost 90% oil content, and the well is performing similar to Lower Spraberry wells in the area. We continue to watch offset performance and believe that this zone has the potential to peak capital within our drilling portfolio in a constrained capital environment, and we will look to drill another Lower Spraberry well in the southern region next year. Finally, I will note that we will be drilling 2 additional appraisal wells in the coming quarters as part of our fast-follower strategy. Importantly, we have seen strong offsetting well results that support our subsurface views in both areas. We are currently drilling our first middle Spraberry well in Midland County and have plans to drill our first Cline or Wolfcamp D well in Reagan County later this year. On the next slide, I want to spend some time on achieved well cost reductions that further enhance the capital efficiency created by type curve outperformance. I will use our 7,500-feet laterals as an example, but similar cost dynamics hold for both longer and shorter laterals. With the commodity price downturn earlier this year, we set an aggressive target of achieving a 30% reduction in total completed well costs for our team. Assuming an equivalent well design, we estimate we have reduced our well cost approximately 20% to 25% from last year. We continue to work with our service providers to improve efficiencies, which will lead to further cost improvements. We have also made changes to our completion designs over the last few months, starting with increased proppant concentrations which have delivered improved production performance and, more importantly, a clear improvement in well economics. In addition, we have started to test tighter spacing between frac stages in recent wells and hope to see similar improvements in our return portfolios. Given the substantial capital reductions we have achieved today, we are using part of these savings to fund these completion enhancements while still delivering 7,500-foot wells at just over $6 million. On slide 8, you can see the dramatic CapEx reductions that have been achieved over the last few quarters, with a decrease of 20% from last quarter alone. This decrease would have been higher under normal operations, but the unplanned battery upgrades at our Neal lease, which I discussed earlier, offset a portion of the decline. These upgrades brought our total facilities cost to full $8 million for the quarter, which was $4 million above the first quarter. Moving forward, capital costs will be lower as we roll in the full quarter of cost reductions achieved throughout the second quarter. We are very pleased with the partnerships developed with our service partners as we all work through this challenging commodity price environment. Joe Gatto, our CFO, will pick up on slide 9 with a financial review of the second quarter and an update on guidance metrics. Joe? -------------------------------------------------------------------------------- Joe Gatto, Callon Petroleum Company - SVP, CFO and Treasurer [5] -------------------------------------------------------------------------------- Thanks, Gary. I will start with an overview of the key components of revenue in the quarter. Daily production volumes increased sequentially by 11% over the first quarter of 2015 and 80% over our production levels for one year ago. Total revenues in the quarter, excluding settled hedges, were $39.2 million, or approximately $45.31 realized per BOE of production relative to $39.42 per BOE last quarter. Our unhedged oil price realizations were approximately 91% average Nymex prices relative to 90% in the first quarter. We benefited from improvement in the Midland and Cushing basins differential. We've continued to see additional improvement in the differential in recent months and also expect to benefit from reduced transportation costs as our southern fields are put on gathering systems. The East Bloxom [lack] unit has just been commissioned, and we expect our Garrison Draw and Taylor Draw fields to be put on systems in the next two to three months. Our realized natural gas prices per MCF experienced a small sequential decline due to underlying benchmark pricing, but we did see a slight uptick in realizations as a percentage of Nymex, with some recovery in NGL contract pricing. Our hedge position added some support to our total revenues, with total cash settlements related to our hedging program totaling $5 million, or $5.74 per BOE in the quarter. For the remainder of 2015, we have two-thirds of our estimated oil volumes hedged at an average price of $66.17. We also have over 20% of our projected 2016 oil volumes hedged at an average of $61.50. Slide 10 details our improvements across each category of key expenses added to our capital efficiency at both the wellhead and corporate levels. LOE, including workovers, was $7.59 per BOE for the quarter, representing a quarterly decrease of 16% on top of a decrease of 20% last quarter. This reduction reflects both the allocations of our fixed LOE across a growing production base as well as lower overall workover expenses. Adjusted G&A expense, which excludes the impact of mark-to-market valuation items and non-recurring items, was $3.9 million in the second quarter of 2015, or $4.53 per BOE. Of this amount, $3.85 per BOE was recurrent cash expense, representing a 39% reduction compared to the first quarter of this year. This decrease clearly reflects the impact of our proactive corporate cost reduction plan implemented in the first quarter as well as spreading our G&A across a growing production base. Moving to DD&A on the lower-left corner of this slide, we reported to 14% decrease on a BOE basis compared to the first quarter, reflective of improved capital efficiencies related to reserve additions to future development costs. Turning to slide 11, you will note that from a leverage and long-term capital perspective total debt to adjusted 2Q EBITDA stood at under 3 times on an annualized basis. From a liquidity stance, our position remains strong, with over $175 million of cash and credit availability to complement the internal cash flow generation from an increasing production profile. A snapshot of that cash flow generation is shown in the right-hand chart in the form of an EBITDA margin per BOE produced. Despite dramatic shifts in commodity pricing over the last several months, our EBITDA margin remains at 70% of total revenues as we reduced our cash cost structure by over 35% in the last year. This margin resiliency, when combined with the decreasing CapEx spend per BOE produced, enables us to continue to grow production while progressing to our stated goal of becoming self-funding by mid-2016. I will now turn to slide 12, which illustrates our production estimates for the remainder of the year. It provides guidance on hedging and key expense items. You'll see that our production guidance has been increased by an additional 6% for the year, though we have a 10% increase last quarter. And our cost guidance continues to move lower with efficiency gains and organic production growth. We hope to exit 2015 at 10,500 BOE per day in the fourth quarter, which is up approximately 45% from the prior year. Finally, slide 13 provides our current high-level view of the business as we progress into 2016. With continued execution of our 2-rig program and the impact of increasing capital allocations to the Lower Spraberry, we expect to deliver annual production growth in excess of 20% over 2015, targeting 11,750 BOE per day for the year. We also forecast an associated decrease of approximately 20% in our operational capital spending at current well costs, reflecting a lower blended rig count for the year and a lower working interest mix in our drilling program. Why we expect it won't be a straight line from here through next year, given market volatility, we see a path to becoming self-funding in the middle of 2016, as shown in the line chart on the right-hand side of this slide. The analysis is meant to be illustrative, with simplifying assumptions that drive directional guidance under both strip and research consensus pricing scenarios. Of note, we have assumed no additional decreases in LOE as well as no incremental type curve impact from new completion initiatives. The bars represent cash inflows and outflows, with the lines showing the resulting net discretionary cash flow calculations under the two scenarios. With our achieved capital efficiency gains under a focused 2-rig program, you can see a dramatic improvement in net cash generation profile taking hold in the second half of 2015. With continued production growth and our relatively flat quarterly cap spend, we expect cash flow neutrality in the second half of 2016, assuming research consensus views on pricing. Although we fall a little shy of that goal using current strip pricing and an assumed 5% reduction in well cost, we believe it to be achievable in a low $50 oil environment. We believe the potential impact of type curve improvements from enhanced completions and other cost structure reductions would ultimately enable us to achieve our goal in this price scenario as well. In any case, these examples provide visibility for continued progress toward self-funding over the next few quarters while delivering sustained production and reserve growth. I will now turn the call back to Fred for some final comments. -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman, President and CEO [6] -------------------------------------------------------------------------------- Thank you, Joe, and Gary as well. As you can tell, we are very pleased with the progress we are making and feel like we are well-positioned with the assets we have and the team we have out here. We feel like they are executing well, and we feel like that we are well-positioned to work through this current commodity cycle. So with that we will open the call to questions. ================================================================================ Questions and Answers -------------------------------------------------------------------------------- Operator [1] -------------------------------------------------------------------------------- (Operator Instructions) Will Green, Stephens. -------------------------------------------------------------------------------- Will Green, Stephens Inc. - Analyst [2] -------------------------------------------------------------------------------- I wonder if we could touch on the Spraberry wells you guys talked about in some detail on slide 5. Very impressive results there. I know some of those are normalized to the longer lateral. But if we think about these wells on that shorter lateral, do you guys have a sense for what EUR those 3 operated wells are tracking after 180 days so far? -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman, President and CEO [3] -------------------------------------------------------------------------------- Yes. We are very encouraged with these results, as you can see. In fact, that slide actually includes both -- this is normalized, of course, to 7,500 feet. But you can see even the early time performance on a normalized basis. The Pecan Acres wells, which are the short laterals, and the Cassselman 40, which is a short lateral, are performing quite well. So those wells are going to have the EURs in the 800- to 1-million-barrel type ranges as we go forward. We are very encouraged with that. The early time performance is very strong. And certainly that early time performance is helpful for our current production performance as well as the returns that we're -- significant returns, actually, we are seeing from that type of a horizon. That's the main purpose for shifting our focus in, really, the rest of 2015 and the majority of 2016 to the Lower Spraberry development. -------------------------------------------------------------------------------- Will Green, Stephens Inc. - Analyst [4] -------------------------------------------------------------------------------- And you guys are drilling and completing in that area, I guess, those types of laterals for sub $6 million, it sounds like, at this point, too? -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman, President and CEO [5] -------------------------------------------------------------------------------- That is correct. We are a little over $5 million. I think the last phase (inaudible) was $5.4 million. And we always try to, again, under-promise and over-deliver there. So we are still working hard to deliver those types of wells at very, very good costs. -------------------------------------------------------------------------------- Will Green, Stephens Inc. - Analyst [6] -------------------------------------------------------------------------------- That's great. And then maybe on the profit-loading side, it looks like you guys settled out, you guys stair-stepped up. It seems like you were testing higher loads as well. Does it feel like the right level now? Were you getting the EUR improvement still, and just the cost didn't justify the amount? You were seeing diminishing returns? Maybe you could just walk us through how you guys are feeling about that. -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman, President and CEO [7] -------------------------------------------------------------------------------- Yes. Well, we talked about this a little bit last quarter when we were talking about the 1,900 pounds per foot that we pumped at Taylor Draw, thinking that we could significantly enhance the performance of those wells in that lower-pressure area. It worked. Those wells are certainly outperforming our other wells. But we didn't really get the bang for the buck to go up to that level of sand loading. So we pushed that back for the Wolfcamp B. We are anywhere from 1,350 to 1,600 pounds per foot, depending on how deep we are and where we are in the basin and then our ability to place the sand. And then, for the Lower Spraberry we are anywhere from 1,500 to 1,700 pounds per foot. And we think that's a nice little sweet spot. And again, we pay close attention to what goes on around us. We pay close attention to three companies. Not being disrespectful to the others, but we pay a lot of attention to what Pioneer is doing, what Fang is doing and what RSP is doing. And those guys, I think, are doing similar type of sand-loading profiles for the exceptional wells that they are delivering. -------------------------------------------------------------------------------- Will Green, Stephens Inc. - Analyst [8] -------------------------------------------------------------------------------- Is that an area where you guys have maybe looked to maybe retest some higher proppant loads, if you did get maybe some lower cost on the sand side? Is that an area that you are seeing actually some price concessions that potentially you guys would maybe retest that theory? -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman, President and CEO [9] -------------------------------------------------------------------------------- We might very well do that, Will. What we are focused on presently, of course, now that we think we have found the sweet spot on sand loading, is actually our stage basin. Historically, we have been about 250 [sub-linked] stages. And recently we just pumped a couple -- 3 different wells at 200-foot spacing for our stages. And with that, I think that will ultimately increase our overall sand loading across the entire lateral length. But we are going to work on that for now, but if we continue to get concessions on sand pricing, which we think continue to roll through our pumping services organizations, we will continue to be flexible. -------------------------------------------------------------------------------- Will Green, Stephens Inc. - Analyst [10] -------------------------------------------------------------------------------- Great. I appreciate all the color, guys. Thanks. -------------------------------------------------------------------------------- Operator [11] -------------------------------------------------------------------------------- Jeb Bachmann, Scotia Howard Weil. -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil Incorporated - Analyst [12] -------------------------------------------------------------------------------- Just looking at first on the 2016 growth, it looks like a pretty meaningful step up from what you guys are talking about at the end of June/early July from the 10 to, now, the 11.75. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [13] -------------------------------------------------------------------------------- Jeb, are you still there? -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil Incorporated - Analyst [14] -------------------------------------------------------------------------------- Yes. Can you guys hear me? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [15] -------------------------------------------------------------------------------- I can hear you. -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil Incorporated - Analyst [16] -------------------------------------------------------------------------------- Okay. Can you hear me, Gary? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [17] -------------------------------------------------------------------------------- Yes, sir, I can. -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil Incorporated - Analyst [18] -------------------------------------------------------------------------------- So for that to step up in the production for 2016, is that, as you said, strictly a function of the Lower Spraberry wells and the participation in more wells with the lower working interest? Is that accurate? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [19] -------------------------------------------------------------------------------- Yes, Jeb. That is right on. It's not just the Lower Spraberry because we don't want to discount this tremendous performance we are getting from the Wolfcamp B and Garrison Draw. That is a very nice sweet spot for the Wolfcamp B, which is, again, part of the reason we are focused on the Cline there as well; it looks very good as well. But the greater uptick in performance really comes from the early time and steady performance of a more extended focus on Lower Spraberry results. And so that's where we're headed. And I think that the results that we actually have now, the outperformance even this quarter was attributed to the sustainability of the Lower Spraberry and the wells that we have as well as Pecan Acres Lower Spraberry that we just brought online. And then the non-op Lower Spraberry well that was drilled by Diamondback at Carpe Diem. So without question, that Lower Spraberry is the real deal. -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil Incorporated - Analyst [20] -------------------------------------------------------------------------------- And, Gary, looking at 2016 on the infrastructure side, I know you guys had a little bit higher number this quarter. Do you foresee that number going back to [4] in 2016 to keep pace with the 2 rigs, or are there additional expenditures needed to keep everything moving on the completion side? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [21] -------------------------------------------------------------------------------- No, I see that coming back to our normal about $4 million a quarter, maybe a little bit more. But it won't be like we just had. And I'll explain a little bit more color to what we just had. We had a -- remember, Bloxom was where we actually started this overall development. So we had a mix of both ESP, rod pumps, gas lift wells. And we did a very good job keeping all that pulled together. But when we pulled those last couple of wells on we saw that we had some bottlenecks in our facility that just weren't working for us. So we had to make a decision to go ahead and split that facility into two. And that's really what caused all that additional cost in the second quarter. But going forward, as we continue to build out our facilities, the greater area that we will have more infrastructure cost is going to be in our CaBo area because that's still relatively new for us, and we are very excited about all the potential it has. But as we move from section to section, there will be additional infrastructure cost to build out in order to handle the additional growth in production, the additional water and then the frac capacity that we need in order to fracture-stimulate these pad wells. But that's primarily where our new infrastructure guidance and construction will occur. Everything else is pretty well built out, and there will just be minor enhancements as we go forward. -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil Incorporated - Analyst [22] -------------------------------------------------------------------------------- And just looking on the efficiency side, where do the drill days come down from, from 4Q to today, in the percentage of that overall decrease in the well cost? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [23] -------------------------------------------------------------------------------- I don't know that -- I'm sure that we've knocked a couple of days off our typical well designs. But I can't tell you those numbers on this phone call right now. But our drilling guys are keyed in to -- again, the guys that out-drill us -- there's only one company out here that out-drills us. And we are very, very close relationships with those guys, and we are always pushing each other to add additional enhancements to drill faster. The real key for enhancements and for greater efficiency, I believe, is going to be coming in our completion designs. That's going to come from just being smarter about what we do. It's really working with ProPetro Services. The wells that we are currently tracking we have shifted to the 24/7 cycle to see if we can then increase the number of stages we get per day substantially in order to reduce, one, longer-term rentals, bring production on sooner and reduce a couple of days on the completion side, but also to be smarter about how we actually pumping our completion. We've done a lot of recent technical work around smart completions, and we just had a paper presented at ERTEC in San Antonio. And that talks about being smart, learning quickly about how you pump a stage in a well, how you plan your stages based on the amounts of quartz or sand or clay content in the formation along the lateral. And if we get smarter and smarter about what we can anticipate and then see those responses as we are fracking those wells, we can move through a frac very quickly. We can take the stages that we think will frac easier and place more sand. And we think if we see a stage that we think is going to frac harder, we can minimize the amount of work we put on that and just really focus on the areas we can best connect to the natural fractures. -------------------------------------------------------------------------------- Jeb Bachmann, Howard Weil Incorporated - Analyst [24] -------------------------------------------------------------------------------- Great. I appreciate the answer, Gary. -------------------------------------------------------------------------------- Operator [25] -------------------------------------------------------------------------------- Ron Mills, Johnson Rice. -------------------------------------------------------------------------------- Ron Mills, Johnson Rice & Company - Analyst [26] -------------------------------------------------------------------------------- Gary, you hit a lot on Lower Spraberry, and it's pretty evident why you are going towards that route. When you look at 2015's capital program, Spraberry versus Wolfcamp and how the 2016 program would look, can you just talk about the relative amounts of Spraberry versus Wolfcamp? And are you also -- are you testing the tighter fracking roles in both the Wolfcamp and the Spraberry and seeing similar results? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [27] -------------------------------------------------------------------------------- Ron, I don't know that I can answer your question specifically around the percent focus on Lower Spraberry versus Wolfcamp B or even Middle Spraberry at this point in time. I know our greater focus is going to be at Casselman, Bohannon and Pecan Acres and Carpe Diem, where our Lower Spraberry and -- hopefully. But we certainly are encouraged by what we are seeing from both Diamondback and RSP in the Middle Spraberry; those are eye-popping results as well. But that's primarily where we will be focused on the Lower Spraberry activity is in our central Midland area. Again, I don't want to discount what we are seeing at the Wolfcamp B at Garrison Draw; those are very good results. As far as the question related to sand loading as well as frac stages, we are testing that in both areas as well as paying close attention to well inventory and spacing between wells. We see what Diamondback is doing -- 10 wells per section, the close spacing that they have there, about 513 feet apart. And we see what RSP is doing in the Lower Spraberry, with 10 wells per section in a chevron pattern. And we think, as we are looking through this and we are seeing at least the reservoir characterization of the Lower Spraberry, we're going to be closer from our -- we will actually be increasing from 8 to 10 or 11, depending on a recent -- on the test that we are planning to perform on our next pad at Carpe Diem. So our best opportunity is increased inventory and increased well spacing -- reduced well spacing, I guess, between wells in the Lower Spraberry. -------------------------------------------------------------------------------- Ron Mills, Johnson Rice & Company - Analyst [28] -------------------------------------------------------------------------------- Is that specific to the Lower Spraberry in terms of 10 wells per section, or do you think that can also apply to the Wolfcamp? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [29] -------------------------------------------------------------------------------- No, I'm not ready to jump to the Wolfcamp on that yet. And again, the difference is in the way the reservoir characterization works. Lower Spraberry has greater props; it has good oil in place. Bit lower pressure, so you're going to have to place more wells in order to get access to the total resource. It's not quite that way with the Wolfcamp B, so we are still going to stick to our 7 wells per section in the Wolfcamp B, for now. But very encouraged with the exceptional results that others are delivering with that tighter spacing in the Lower Spraberry. -------------------------------------------------------------------------------- Ron Mills, Johnson Rice & Company - Analyst [30] -------------------------------------------------------------------------------- Okay. And then on the well cost side, I just want to make sure I get this right. You talked about continuing to target some further cost reductions. It seems like with the tighter spacing and different proppant loading that on the completion side that has chewed into some of the cost savings. But if I'm reading the chart right, does it look like versus your prior targets, flat to up 10% well costs, but you are seeing a 25% EUR uplift on slide 7? Am I reading that chart correctly? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [31] -------------------------------------------------------------------------------- Yes. On slide 7 what we are showing you is really the current total, where we are today, which includes all the enhancements that we have been talking about. And, yes, a significant uplift in EUR projection with higher sand loading. We are still in the early stages of flowing back the wells that we just did the shorter spacing on, so we can't really talk too much about that yet. But ultimately I think we are still focused very much on efficiency gains like I was talking to you about with ProPetro. And I can still see in this commodity price environment that we've still got to challenge all of our service providers to even come down even further. This -- we've had a plateauing of some cost reductions when prices went back up to $60. But with where we are now, I think everyone is taking a longer view of where this is going to be. And at the end of the day, another 5% across the board, even though we've probably got the lowest drilling cost in the basin today, 5% across the board against all other categories is probably not unreasonable. -------------------------------------------------------------------------------- Ron Mills, Johnson Rice & Company - Analyst [32] -------------------------------------------------------------------------------- And then last one for me -- on slide 5, where you show the well [cums] versus the type curve, any early feeling as to what is driving the continued performance? If you look at in both slides, only one of the seven well [cum] curves even starts to really show the anticipated curve. What's driving that performance? Or maybe, for lack of a better term, is it a flatter-than-expected decline? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [33] -------------------------------------------------------------------------------- It is, Ron. It's really us getting more comfortable with our own level of knowledge and experience with the Lower Spraberry, on the left-hand side of that chart. We saw all the discussion and we were paying attention to all the previous reporting on that area, but we wanted to prove it to ourselves. And that really comes down to porosity and establishing effective fracture stimulations in that zone, connecting to the natural fractures. They give you a longer sustained performance and shallower decline in the Lower Spraberry. On the right-hand side at Garrison Draw, that's just a very high-pressure area for the Wolfcamp B. It's deeper, it's oil rich and we're just in a nice sweet spot for the Wolfcamp B there at Garrison Draw West. -------------------------------------------------------------------------------- Ron Mills, Johnson Rice & Company - Analyst [34] -------------------------------------------------------------------------------- All right. Well, thanks again. -------------------------------------------------------------------------------- Operator [35] -------------------------------------------------------------------------------- Irene Haas, Wunderlich. -------------------------------------------------------------------------------- Irene Haas, Wunderlich Securities, Inc. - Analyst [36] -------------------------------------------------------------------------------- Congratulations on a really strong quarter. I have a question that's probably a little more on the industry in general. 10 months into this downturn, it's just been amazing to see how everybody has been cutting costs and increasing production. So this quarter, a lot of the beats really had to do with volume doing better, cost continuing to be lower. I would like to get your feeling as to whether this trend, we could imagine this to continue into the second half of this year. And also, what is your payback period these days after having adjusted everything for a typical well? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [37] -------------------------------------------------------------------------------- Yes, I'll start on that, I guess, and maybe Joe or Fred have some other things to talk about. But this is a very resilient industry, obviously. We got into a point where we were running as fast as we could, trying to prove up as much inventory as possible. In this price environment, everybody in the industry -- and I applaud everybody that is out there doing this type of work today because it's not easy. In how they, one, said let's do this together. Let's not fight each other. Let's not go into a battle with our service providers. Let's talk to our service providers about what we need. Let's talk to them as partners about where we need to be in order for us all to go through this together. And I think that's what's probably different more about this downturn than previous ones is that we've learned. We've learned that it takes an entire team effort from our service providers to our technical teams to our operating groups, to everybody that is focused on what it takes to, one, drill and complete and then ultimately produce this resource. So, again, the industry and everybody involved in the industry has responded incredibly well in order to work through this commodity price swings that we've seen. Now, will it continue? Of course, I think it will. And, again, we have to. This industry is very resilient to the point where we will always find a way for everyone to participate and have a margin to work with in order to grow their companies and add value. And so I think it will continue. So I'm real pleased, especially with the service providers that are helping Callon through this. And even the Callon team, the technical team that we have now focus on technology and help us truly drive some more efficient completions and less prime, less water, less sand or even potentially more sands, their connection to natural fractures, depending on what we see even before we drill a well. so every company is working on those types of enhancements, and everybody's doing a phenomenal job. That's why it has been so spectacular in order to work through this downturn. The other part about the downturn was we said, hey, we are going to continue working so long as we can work together. And that's what has pulled all this together for all the companies that are continuing to drill out there today. I forget -- after that long answer, I forget your second half of that question. -------------------------------------------------------------------------------- Irene Haas, Wunderlich Securities, Inc. - Analyst [38] -------------------------------------------------------------------------------- Your payback period, after all is said and done, versus a year ago. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [39] -------------------------------------------------------------------------------- Yes. We are still right about two years payout for a typical well. -------------------------------------------------------------------------------- Irene Haas, Wunderlich Securities, Inc. - Analyst [40] -------------------------------------------------------------------------------- Great. Thank you. -------------------------------------------------------------------------------- Operator [41] -------------------------------------------------------------------------------- Neal Dingmann, SunTrust. -------------------------------------------------------------------------------- Neal Wheatly, SunTrust Robinson Humphrey - Analyst [42] -------------------------------------------------------------------------------- This is [Neal Wheatly] in for Neal Dingmann. Just a quick one from me. I know you guys have had a lot of success recently in the Lower Spraberry. Just curious on your thoughts on the Middle Spraberry, given what other guys are doing. Thanks. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [43] -------------------------------------------------------------------------------- We are very excited about the Middle Spraberry. Appreciate your asking that question. That's why we are drilling our first Middle Spraberry well on the pad that's currently drilling at our Casselman and Bohannon section there in our Central Midland Basin. Without question, the results coming out of Diamondback and RSP are phenomenal. Those guys have done a lot of work. They've applied a lot of technology. They're very smart, and have done very well to de-risk that zone. Our petrophysical work says ours is a good as theirs. So very excited about the Middle Spraberry. -------------------------------------------------------------------------------- Neal Wheatly, SunTrust Robinson Humphrey - Analyst [44] -------------------------------------------------------------------------------- Perfect. That's it for me. Thanks, guys. -------------------------------------------------------------------------------- Operator [45] -------------------------------------------------------------------------------- Ipsit Mohanty, GMP Securities. -------------------------------------------------------------------------------- Ipsit Mohanty, GMP Securities - Analyst [46] -------------------------------------------------------------------------------- Thanks for taking my questions. My first one is a little broader, for Fred or Joe. You have talked about cash flow neutrality in the second half of 2016. Just curious to see your early thoughts and what will be the road forward from there. Would you use that to lever down balance sheet, or would you to take it to accelerate and bring the NPV forward? -------------------------------------------------------------------------------- Joe Gatto, Callon Petroleum Company - SVP, CFO and Treasurer [47] -------------------------------------------------------------------------------- I will take a crack at that. I think right now, as we talked about, we are just developing that visibility. So while we are running scenarios past sort of mid-2016 at this point, I don't have anything definitive. But I think directionally what we would like to see is some de-levering on the balance sheet from a debt-to-EBITDA perspective before we would look to deploy on another rig. But as we approach the path, we walked down this path that we've laid out, visually we will start to moderate our outspend. We will start -- we will plateau on that debt to EBITDA, start to improve that with a growing EBITDA base and minimizing our outspend. As we get closer to that, our scenario planning, we will start incorporating looking at a third rig in the back half of 2016 and into 2017. Depending on what our cost structure is, that has really been a big driver for us in terms of that decision. It's tough to tell where the commodity is going to go. We need to be as smart as we can on where our cost structure is from a capital-per-well perspective, from an operating cost perspective, overall cash margins that really drive our decision-making. When we feel comfortable where we are going to a level-set there, where is the potential, what are we going to have to potentially give back in terms of that cost structure as hopefully we see a little bit of recovery in oil prices, that's going to dictate our plans. But right now I think we would like to see some deleveraging before we get serious about that third rig at this point. -------------------------------------------------------------------------------- Ipsit Mohanty, GMP Securities - Analyst [48] -------------------------------------------------------------------------------- Okay. And my second question is more about M&A, specifically to the Central Midland area, where clearly your Lower Spraberry is outstanding but is limited -- but you are drilling longer laterals is limited by the (inaudible) geometry. You have seen some recent packages, specifically the [RSP 1], come around. Just your thoughts on how you plan to address that issue in the Central Midland. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [49] -------------------------------------------------------------------------------- I guess one way we are addressing it today -- this is Gary Newberry. But from where we addressing it today at Pecan Acres, actually, we're partnering with RSP on delivering longer laterals between their sections to the South and our section there that we operate in section 23. So anywhere we can partner and drill longer laterals, we will. We've got very good relationships with the people around us. This is where we are geometrically, or geometry limits us, we do the very best job we can to back drill and actually get the longest lateral length possible. So the more important thing is, even in those short laterals for the Lower Spraberry, the economic results are stellar. So we would love to drill longer laterals, but it's certainly not diminishing our encouragement that we have for the wells we have today. -------------------------------------------------------------------------------- Ipsit Mohanty, GMP Securities - Analyst [50] -------------------------------------------------------------------------------- Okay. And just staying on that, and this is my last one, would be going back to slide 13 and your early outlook for 2016. I appreciate your doing that. But I'm curious what the average length of lateral that you have guided toward here or you have incorporated in your guidance because clearly the longer laterals in Central Midland look great. Your type curves are four 3,500, I believe, but you are probably drilling smaller ones because of the lease. What kind of average length of laterals have you incorporated in your guidance for 2016? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [51] -------------------------------------------------------------------------------- Joe, do you have that number? -------------------------------------------------------------------------------- Joe Gatto, Callon Petroleum Company - SVP, CFO and Treasurer [52] -------------------------------------------------------------------------------- While at the CaBo lease our modeling 5,000-foot laterals, we do have those fair amounts at Carpe Diem. We also have, as Gary talked about, the opportunity to partner at Pecan Acres and doing some longer laterals. So that's probably around in the low 6,000 type of range, on average, just given the offsetting work that we're doing at Carpe Diem and Pecan Acres bleneded with what we are doing at CaBo. -------------------------------------------------------------------------------- Ipsit Mohanty, GMP Securities - Analyst [53] -------------------------------------------------------------------------------- Thank you, guys. Great quarter. -------------------------------------------------------------------------------- Operator [54] -------------------------------------------------------------------------------- Ryan Oatman, Cowen and Company. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [55] -------------------------------------------------------------------------------- Great report. Appreciate the fantastic color on 2016. Gary, I was wondering if you could speak to what you are seeing with these stacked laterals in the Wolfcamp B and Lower Spraberry. Obviously very good results there, production almost 200 barrels per lateral foot. The question is, do you see some benefit to the Wolfcamp B wells by completing in these formations at the same time? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [56] -------------------------------------------------------------------------------- Specific to the question about the benefit to the Wolfcamp B and the way we are going forward with our planned development, I see no benefit to the Wolfcamp B just because we are partnering with -- we are drilling the Lower Spraberry to the Wolfcamp B. So, no, I don't see any benefit. The wells are just spectacular. That Central Midland Basin area for the Wolfcamp B as well as the Lower Spraberry and likely the Middle Spraberry is just a great asset to have. So, no, I see no real benefit to doing it the way we are. We are paying very close attention -- Ryan, while we are on it -- to the well spacing that RSP is doing between the Wolfcamp A and the Wolfcamp B. That's very interesting to us, and the fact that their Wolfcamp A wells are spectacular. And they are doing Wolfcamp A/Wolfcamp B type of co-development. And since we are doing the development together at Pecan Acres, we're actually talking about how we move forward in a manner that might incorporate a different type of spacing. We only went to the Wolfcamp B in the Lower Spraberry because we saw that as the best value add today. We are a very value-focused Company. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [57] -------------------------------------------------------------------------------- That is helpful. And you preempted my next question about what that means for the Wolfcamp A, so certainly appreciate that. Do want to shift to the Southern Midland Basin here. Very good results from the Wolfcamp B at Garrison Draw. I know you have tested the Lower and Upper Wolfcamp B at East Bloxom. You've got a nearby peer work in Wolfcamp A and B laterals together. Wolfcamp A, down there in the South, do you feel like that formation can compete at East Bloxom and Garrison Draw? Or do you feel the Lower Spraberry or Wolfcamp D may be a better second formation to shift to there? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [58] -------------------------------------------------------------------------------- No, we have an exceptional Wolfcamp A well at Garrison Draw right now. That's one of the best Wolfcamp A wells down in the second part of the basin. So, yes, the Wolfcamp A in places can compete quite well. So very excited about that. Like I mentioned, we are about ready to drill a Cline well in Garrison Draw as well because we see exceptional results coming from Pioneer about four miles to the west of us. And when we do our petrophysical analysis and all the technical work related to that area, we think we have as good a zone or better simply because of oil in place targets and what we believe to be something that we can get access to and deliver results that are as good as or better than some of the best wells that they are delivering. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [59] -------------------------------------------------------------------------------- That's great, that's great. And then, Joe, when I look at slide 5, I think we have touched on it in prior questions here. But recent wells do appear to be significantly outperforming the type curve over time, given the shallower declines. I wanted to see if I could peel back the onion a little bit here on 2016 guidance. Does that really reflect the type curve that you are seeing, or is there some benefit there for the recent wells outperforming that type curve? -------------------------------------------------------------------------------- Joe Gatto, Callon Petroleum Company - SVP, CFO and Treasurer [60] -------------------------------------------------------------------------------- We've been -- our planning is always based on our current type curves and running that out. So as we continue to see sustained improvement on a longer-term basis then we will start dialing in more of that. But while we have some good history and is building, this isn't really incorporated in 2016, running our existing type curves that are obviously still pretty strong. It's close to 1 million BOE for the Spraberry on this normalized look. But as we move forward we continue to see these types of longer-term rates. We will start revisiting that as we get closer to 2016 and nailing down our real plans. But for right now, really, that last page is a high-level look at where we are in 2016 and still driving some nice growth off the existing curves. -------------------------------------------------------------------------------- Ryan Oatman, SunTrust Robinson Humphrey - Analyst [61] -------------------------------------------------------------------------------- Very good. That's it for me. Thanks, guys. -------------------------------------------------------------------------------- Operator [62] -------------------------------------------------------------------------------- Mo Dahhane, Northland Capital Markets. -------------------------------------------------------------------------------- Mo Dahhane, Northland Securities, Inc. - Analyst [63] -------------------------------------------------------------------------------- Just got a couple of quick ones from me. On that Wolfcamp B well in Reagan County, can you talk a little bit about what type of (technical difficulty) -- -------------------------------------------------------------------------------- Operator [64] -------------------------------------------------------------------------------- I'm sorry. Mr. Callon, are you able to hear me? -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman, President and CEO [65] -------------------------------------------------------------------------------- Yes. -------------------------------------------------------------------------------- Operator [66] -------------------------------------------------------------------------------- Mr. Dahhane, please go ahead. -------------------------------------------------------------------------------- Mo Dahhane, Northland Securities, Inc. - Analyst [67] -------------------------------------------------------------------------------- Just got a quick couple ones. One, on the Wolfcamp B, you guys plan to drill in Reagan County. Just curious what kind of subsurface work you guys have done that led you to make that decision to drill that well. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [68] -------------------------------------------------------------------------------- The Wolfcamp B in Reagan County, being the Garrison Gulf (inaudible) depicted on slide 5 -- this has been the, really, the start of the play back several years ago. We saw that it was a little deeper, a little bit more rich. We have exceptional results coming from the Wolfcamp B in our Upton County at East Bloxom field. So this is a bit of a step into really the deepest and most central part of the basin for us. Between what we know we have at Taylor Draw and what we know we have at East Bloxom, it was a fairly easy jump to say, hey, let's go drill some good wells here. -------------------------------------------------------------------------------- Mo Dahhane, Northland Securities, Inc. - Analyst [69] -------------------------------------------------------------------------------- Appreciate that. And then just quickly on that Cline well or the Wolfcamp B you plan to drill in the fourth quarter, can you talk a little bit about how you plan to complete that well? Are you going to use the same, similar (inaudible) design, or are you going to tweak that design, given the deeper formation? -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [70] -------------------------------------------------------------------------------- No. We will go into it with a similar completion thought. But we will do a lot of research between now and then about what others in the industry are doing. We will certainly try to collaborate with other experts in that area. Again, the well results are very, very good. We see results north of us that are exceptional and results west of us that are exceptional, both drilled by other companies. So we will learn as much as we can from them, just like we always do. We always want to be at the top of the learning curve as we go forward. But going into it, we have a similar frac design concept that will be as much sand loading as we can possibly place as well as the best type of curve clusters in order to get as good entry into each of the perforations as well as staged basin. As we go forward, we will do the best we can with what we know. -------------------------------------------------------------------------------- Mo Dahhane, Northland Securities, Inc. - Analyst [71] -------------------------------------------------------------------------------- I really appreciate the color. And congrats again, guys. -------------------------------------------------------------------------------- Operator [72] -------------------------------------------------------------------------------- Phillips Johnston, Capital One. -------------------------------------------------------------------------------- Phillips Johnston, Capital One Southcoast, Inc. - Analyst [73] -------------------------------------------------------------------------------- Just a couple quick questions for Joe. First, I'm wondering what your expectations are going into the fall redetermination season. -------------------------------------------------------------------------------- Joe Gatto, Callon Petroleum Company - SVP, CFO and Treasurer [74] -------------------------------------------------------------------------------- That's an easy question, Phillips. I can't really provide a lot of specific guidance on that at this point, but I can tell you how we approach that process. It's going to be similar to what we did starting January 1 when we saw the downturn in prices and just really wanted to get ahead of the process, over-communicate with our banks, make sure we understand where their hot buttons are, make sure we're over-communicating, make sure we are documenting all the cost reductions we are getting, and make sure that's flowing through their analysis of the collateral package that they are stepping into. I can say that we are doing the same thing. We started probably six, seven weeks ago doing the same exercise for the fall. We are still a couple months out until we get formally into that process. I think with what you can see from the production growth and the reserve growth that underlies that, we feel good about where the business is heading. I think that obviously the wildcards around price decks and where things are set, all we can do is take care of our business. It's showing the type of growth that you can see in the presentation, that we are adding reserves at a good clip. We are delivering real capital-efficient adds with the types of well costs we are seeing. So doing that, getting the cost structure down and the LOEs that are rolling through their reserve reports, and we will just keep staying close to them. I think we are as well positioned as anyone going into the fall. -------------------------------------------------------------------------------- Phillips Johnston, Capital One Southcoast, Inc. - Analyst [75] -------------------------------------------------------------------------------- Okay, that sounds good. Just secondly, you guys have done a great job at driving down your LOE costs. We have seen most companies report lower LOE and cut their LOE forecasts this earnings season. I realize you guys are growing volumes and there is a fixed component, but how much of the reduction is just a slowdown in workover activity, given the weak price environment? I'm just trying to gauge how sustainable that lower trend is. -------------------------------------------------------------------------------- Gary Newberry, Callon Petroleum Company - SVP of Operations [76] -------------------------------------------------------------------------------- I don't know how to give you a percent, but it's certainly significant. And the fact that a good bit of it is being very particular about the workover activity, making certain that there is a clear payout, that we have a clear solution for why our reasons failed, how we fixed that well going forward in order to extend the life of that well and being smart about what we do with the walk-over activity, certainly in this price environment. We have been a bit fortunate, in fact, that now we have got significant horizontal development going on in some of the areas that we have a large number of vertical wells. We have flexibility in whether or not we might go back in and repair a vertical well today in this price environment or just defer that in the future because we have no lease obligations to just to keep them busy. So we are in a pretty good spot to manage that cost in a large way. But I don't want to discount the fact that all of our categories have come down to a certain degree because, again, just like on the capital side, we have focused hard on the expense side. And all of our providers of services and labor and work activities related to maintaining our leases, all of our service providers have been very responsive to our cost needs and have actually lowered their cost of services and goods and services for us as well. -------------------------------------------------------------------------------- Phillips Johnston, Capital One Southcoast, Inc. - Analyst [77] -------------------------------------------------------------------------------- Okay. Thank you, guys. -------------------------------------------------------------------------------- Operator [78] -------------------------------------------------------------------------------- This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Callon for any closing remarks. -------------------------------------------------------------------------------- Fred Callon, Callon Petroleum Company - Chairman, President and CEO [79] -------------------------------------------------------------------------------- Great. Once again, we thank you all for taking time to dial in this morning. As always, if you have any questions in the interim, please don't hesitate to give any of us a call. Thanks so much. -------------------------------------------------------------------------------- Operator [80] -------------------------------------------------------------------------------- The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
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