Coterra Energy Inc. (CTRA) Q4 2010 Earnings Report, Transcript and Summary

Good afternoon. My name is Michelle, and I will be your conference operator today. At this time, I would like to welcome everyone to the Cimarex Fourth Quarter 2010 Earnings and Operations Conference Call. [Operator Instructions] Mr. Mark Burford, Vice President of Capital Markets and Planning, you may begin.

Thank you very much, Michelle. I appreciate everyone joining us today on the fourth quarter conference call. We did issue our financial and operating results for you this morning, a copy of which can be found in our website. We have also posted a presentation today for the year-end results, which is also on our Presentation tab, which I'll refer you to on that as well, which we might refer to from time to time on today's call. I'll also warn you that we'll be making forward-looking statements in this call, and please see the end of our press release for our disclaimer regarding forward-looking statements. Today here in Denver on the call we have Mick Merelli, Chairman and CEO; Tom Jorden, Executive Vice President of Exploration; Joe Albi, Executive Vice President of Operations; and Paul Korus, Senior Vice President and CFO; and Jim Shonsey, Vice President and Controller here in Denver. We have a lot to cover today, so I'll go ahead and just turn the call over to Mick Merelli.

Okay. Thank you, everyone, for joining us today. I'm going to be brief so that we can get to Tom and Joe and Paul, part of the presentation, which is really the meat of it. 2010 was under almost any measure was just an outstanding year for Cimarex. We invested $1 billion in our exploration and development drilling program. We drilled over 200 gross wells. We grew our reserves 23%. We added 560 Bcfe from extensions, discoveries and revisions. We replaced 258% of our production. We had record production of 596 million cubic feet a day equivalent. So that was a 29% production growth over 2009. It was a great year. We had good results out of all of our regions, and we accomplished this out of essentially our cash flow, which is when you put all of that together, I don't know how you'd call it anything, but just a really good year. As we, again, I promise you I'd be brief, so we can get to the guys that can really put the meat on the bones here. As we look into in 2011, we go into 2011 with the deepest inventory of drillable locations that we've ever had. It's a diverse inventory between essentially gas and oil, but it's a multi-year identified drilling inventory. So as we look into 2011, we have a lot of flexibility. The inventory, combined with our financial strength, allows us to do a lot of things. As we go through the year, we may be adjusting from one area to another, but we'll have the flexibility, I think, to do that. We feel very strongly that we're going to get our at least our cash flow down in 2011, and that's barring any big commodity surprise. But even with the commodity surprise, we'll just have to see how it all goes. We look forward to the year. It's going to be a very active year for us. With that, I think I'm just going to turn it over to Tom to kick this thing off, and so the boys can get going on the detailed presentation. Tom?

Thank you, Mick. For those of you that are following along with our PowerPoint that's posted on our website, I'm going to pick this up at Slide 7, and we'll be using the slides to kind of guide my remarks. As Slide 7 shows, it shows our major core operating areas, and most of you who are familiar with our story are quite familiar with this. The selling point in this slide is our reserve increase. 2010 end-year reserves we're showing 1.88 Tcf equivalent. Out of that, 85% is Mid-Continent, 30% is Permian. Our 2010 fourth quarter production is 75% in Mid-Continent and Permian, and that's nicely illustrated by the slide. Moving on to Slide 8, you see our breakdown of exploration and development capital for 2010 and 2011, and this kind of shows that the major slices of our exploration capital pie, exploration and development, our Mid-Continent and Permian, they accounted for roughly 87% of our 2010 capital and will be well over 90% of our 2011 capital. One of the selling point is if you're referring to Slide 8 as you compare 2010 to 2011, I think it's fairly obvious we are picking up the pace in the Permian. Clearly, from a drilling standpoint, releasing standpoint, from an emphasis standpoint, the Permian is our growth arena for 2011. As Mick said, we have a nice mix of opportunities teed up not only for 2011, but for years ahead of us, and the nice thing about that inventory is it's diversified, we can speed up or slow down depending on commodity pricing, our own cash flow and also our results in service cost. So very nice outlook into in 2011, but the selling point is that the Permian is clearly our growth area for 2011. Well, let's focus on the Permian moving to Slide 9. This is just a little summary slide, showing some statistics of where we are in the Permian. Our reserves are up from 2009 to 2010. Our production is up, but the thing I'll focus you on is our acreage is up. We added roughly 70,000 net acres over the last couple of years. Certainly, bulk of that is 2010 addition, and that was centered around a couple of key projects, and we're going to discuss that in a little more detail. Another selling point on Slide 9 is our 2011 capital all in is projected to be a little over $700 million. Depending on where our total budget falls, that will probably be somewhere between 55% and 60% of our total capital. So we're looking forward to a very active year in 2011, certainly, with the Permian being our most active arena. Moving on to Slide 10. I want to focus you into our Permian program. This is a slide that shows Southeast New Mexico and kind of far Northwest Texas. As we said, we have a very small strong land position with that 448,000 net acres. And that's spread over several different plays, and we certainly emphasized that in the past and I'd like to emphasize it now. We have our Abo horizontal play. We have our Bone Spring horizontal oil play. And then one of the things that we'd like to introduce is our unconventional play that really cuts from Eddy County down into Ward, Loving, Reeves County, Texas. It's a fairly significant fairway. It's a lot of real estate. We have about 125,000 net acres in that fairway, and it's multiple objective. We really got into this area -- we've been playing around here for a few years. Have tested some concepts, and we now have some results that we think are significant, and we'd like to discuss them with you. The plays down there are threefold. We have our Penn Shale or what we call our Cisco/Canyon, we have our Wolfcamp objective and we have the Avalon Shale, which is certainly gotten most of the attention out of the industry in the last couple of years. We have two to four rigs running depending on when you quarry us on our White City, Culberson County area and three rigs down in Reeves, Ward Winkler County. I'll come back to that with a little bit of detail. Moving on to Slide 11, I'd just like to introduce the geological framework before we talk in detail about these objectives. The Delaware Basin is a rather broad pressure basin. Slide 11 shows a little 3D rendering that's on the top of the Wolfcamp structure. You can see Eddy and Lea County form there. You can see Culberson County. Our acreage is overlaid in yellow, and you can see that we have some shale plays and then the sediments are shed into the deep basin. So it's a variety of targets from sands along the shelf to more shaly, carbonated-rich sequences in the deep basin. Moving on to Slide 12, I'll kind of focus on some of these unconventional plays. We've been playing this arena, as I said, for a few years. 2010 is really our breakthrough year testing the Wolfcamp. We have drilled now -- in aggregate, we have drilled eight horizontal Wolfcamp wells. We really talk about seven because the first well we drilled was 2007. It was a short lateral. It was before we really understand the completion, so it's almost not a data point in this discussion. But we have identified the Wolfcamp as a very nice, thick, rich target. And Slide 12 compares the Wolfcamp to our Cana play heads up. It depths 8,500 to 10,000 feet, so it's a little shallower than Cana, although this slide doesn't indicated, they're both pressured targets somewhere a geopressure gradient of about 0.7 psi per foot. So it's an overpressured target, and that certainly increases its storage capacity. One of the things you'll notice on Slide 12 is the Wolfcamp is a nice thick target. We have between 607 feet of gross interval between 240 and 400 feet of net interval when we net that out for what is did poorest hard rock. It has reasonable total organic content, 2% to 3% compared to Cana at 3% to 9%. It has good ferocities, 5% to 9%. The recovery factors in targets like this are something we can only guesstimate until we get into a little more science. We currently just drilled one well per section. None of our wells are spaced any closer together than 640-acre spacing, so the recovery factor is a little bit of an arm wave at this point. The key part of this slide is the gas in plays. The Wolfcamp is a very rich, hydrocarbon varying target. We calculate based on logs and cores that we've taken between 150 and 300 Bcf per section gas in plays. So we're just at the very entry of this play for an area that this large with our acreage position. We're only introducing the play. And if we get a lot of questions, you'll probably hear me say we don't know more than what we do know, but I will say, based on our results today, we are very excited about the potential to Cimarex. Moving on to Slide 13, this is a little zoom in on this emerging play concept. On this map, which would be encompassing our White City complex, that's in Eddy County there, that's a block of acreage in Eddy County in which there are the red circles. And then moving from there southeast, we have about 125,000 net acres in this trend. And as I said at the outset, we really do see this as a multi-target trend. And for much of this acreage and our current level of understanding, we're not exactly certain what the primary objective will be. But we believe that one or all of either the Cisco/Canyon, which many refer to as the Penn Shale, the Wolfcamp or the Avalon Shale are going to be perspective. So this is a multi-target area. We're very, very excited about what we have seen and what we do see. We have drilled and completed seven Wolfcamp shale wells in Eddy and Culberson County, and those are shown in red in your slide. And of those seven wells, our first 30-day average production is 6.3 million cubic feet equivalent per day, and that's actual averages from the first 30 days of those wells. Those wells are about 50% methane, 32% natural gas liquids and 18% oil. So we get very nice condensate yields and very nice natural gas liquids processing yields out of that hydrocarbon stream. Thus far, we're currently at around $6.5 million to $7 million per well. Our lateral lengths are about 4,000 feet. And before I move on, I just really want to re-emphasize that we're very much early days. We have drilled, for example, one Cisco/Canyon lateral in our White City complex. We drilled it a few years ago, and we don't have a modern stimulation on it. At the time, the stimulations that we were putting in our wells were a small fraction of what we're doing now. So we've yet to test the Cisco/Canyon objective or what we'd call a modern stimulation. So we're very excited about the potential there. We're very excited about the Wolfcamp. We have drilled an Avalon Shale well at White City, and we've been producing that well, and it's got very, very nice results. On an Mboe basis, it's about an 800,000 Mboe well. So if you look at the overall trend and what people are generally quoting for the Avalon Shale reserves, our well is certainly a high-end well. That said, I will say we're at the gassy end of the trend. So our well is about 60% methane and 40% liquid. So we're very excited about the Avalon Shale potential, very excited about the Wolfcamp potential and very excited about Cisco/Canyon potential, but it's really the Wolfcamp where we can quote actual results with the seven well program today. So we're probably going to be spending about $200 million on these plays in 2011. We're developing our acreage. We're working on our infrastructure. We're driven by results, and thus far, our results are very, very encouraging for this part of the play. We're at the early days. Moving on to Slide 14, this is a little blowup of our second Bone Spring horizontal oil play in southeast New Mexico. Our results continue to excite us there. This slide shows many of our recent wells we brought on and what their 30-day averages are. The selling point here is that our mean 30-day average for the recent wells we have drilled is 670 barrels of oil per day. So we still continue to move our tight curve up as we get better and better results. This is a very exciting play for us, and it will certainly be one of our top five plays for 2011. Slide 15 shows the production growth that we've seen out of that play. In January of 2011, on a gross basis, we were producing 6,000 barrels of oil equivalent out of that play, which is up from practically zero here just two years ago. So this is an internally generated play. We're very excited about it. And before I move off the Permian Basin, I want to just finish by saying we're still actively leasing out here. We're still actively leasing in our unconventional play. We're still actively leasing in our horizontal oil plays in a more conventional targets. We see the Permian Basin as a wonderful growth vehicle not only for 2011, but 2011 and beyond. We are very proud of the work that our team has done in the Permian Basin. They have established a foothold as a major competitor in the Permian Basin. We're going to be there for the foreseeable future, and it's a sustainable business model. Mid-Continent region is shown in Slide 16. Again, these are some of the summary statistics. The selling points here are we significantly grew our reserves, and that certainly a big part of that was our Cana program. We're seeing this as a very significant capital investment in 2011. We'll be just shy of $500 million. And, again, that's a function of our cash flow, our results, service cost and all the various factors that cause us to advance or retreat. But we're very pleased with our results there. Moving on to Slide 17, this shows our current outlay of the Cana-Woodford Shale play. This is focusing in on what we consider to be our core, where we have our 100,000 net acres. In 2010, we drilled 112 gross or 43 net wells. At year-end, we still had 10 wells, waiting on 10 net wells, waiting on completion. And year-end 2010, proved reserves totaled 500 Bcf equivalent, of which 64% is gas, and 36% of that is oil and natural gas liquids. In 2011, we expect to drill about 100 gross and 40 net wells, and we'll have between eight and nine rigs running in the play. This is still an area of active science. There's a lot here we're still trying to figure out, but we are absolutely delighted with this play and what it will contribute to our 2011 and beyond. This is a huge, huge impact to our reserves production and future capital program. We're having very, very good results. Slide 18 shows our Gulf Coast program. Unlike the other two, you see our reserves down year-over-year. That's a function of the volatility of the program. These are wells that come on with immediate impact and go on very steep decline. With that said, we absolutely love this program. We are aggressively drilling and trying to expand it. Slide 19 shows the major operating arena which we have been focusing over the last few years. The last few years would be from 2002 to current. We drilled over 106 wells on this survey on 3D seismic data. We are the major operator in this trend, and we've had just some fantastic results in the last couple of years. We currently have one operated rig. We look forward to increasing results in 2011 and beyond. We're working on acquiring and shooting additional 3D seismic data. So as we said about this play, it's not predictable. It can be volatile, but that said, it is our most profitable program. We absolutely love it, and we're going to try to get as much done as we possibly can. With that, I'd like to turn it over to Joe Albi, our Executive Vice President of Operations.

Thank you, Tom, and thank you, all, for joining our call today. I'm going to go into some detail on our Q4 and 2010 production results. I'll then summarize Q1 '11 and our full year 2011 production guidance, touch on our 2010 and '11 exploitation programs, and then follow up with where we see current service costs. For those of you following along our slides, we have three slides, 21, 22 and 23, that are pertaining to Q4 2010 production and our guidance. I'm going to go into more detail than those slides show, just to give you a feel for the facts and figures that they give you -- some idea of how things are shifting around in production for us. So starting at the top, we had a great quarter in Q4, make hit on that. We've continued upward production trend that we've seen since mid-2009. We reported average fourth quarter production of 604.5 million a day, and four or five items I want to mention there. We came in at the top end of our guidance, which was 580 to 610. We set yet another new record for quarterly company production. This is our fifth consecutive production increase on a quarterly basis. We're up 137 million a day or 29% from our Q4 '09 average of 468 million a day, and we were up about 5 million a day from our Q3 average of 600 million a day. As was the case in Q3, our drilling successes in Cana and the Permian during Q4 continue to offset any declines that we saw in the Gulf Coast, as you may recall, as a result of pipeline shut-ins, natural depletion and the pinching back of a handful of wells in order to protect them from a reservoir management standpoint. We talked a little bit about that during our last call. And in that call, we mentioned that we start off Q4 with our Gulf Coast onshore wells producing at rates below Q3. And we projected our Gulf Coast onshore to average somewhere in the area of 130 million to 145 million a day, while for Q4, we came in at the top end there, right at 145 million a day, but we are also down 13.7 million a day from our Q3 average for onshore Gulf Coast production of 159 million a day. That said, the production adds that we saw from our Permian and Cana programs more than offset that drop, with our fourth quarter Permian equivalent production coming in at 182 million a day, which was up 12.8 million a day from Q3; and our fourth quarter Mid-Continent equivalent production coming in at 271 million a day, which was up 8.2 million a day from Q3. So when the dust settled, our fourth quarter Permian and Mid-Continent programs added combined an equivalent production rate of 21 million a day, which more than offset that 13.7 million a day we saw in Gulf Coast. Also reflecting the Gulf Coast drop, we saw our total company fourth quarter net gas production go down. We came in at 341.5 million a day. That was down 11 million a day from Q3, with 9 million of that drop coming from our Gulf Coast onshore curtailments, deferrals and natural decline. Geographically, 57% of our fourth quarter gas comes from the Mid-Continent, and the Gulf Coast and the Permian each represent 21% of the total. On the liquids side, however, our combined fourth quarter total company liquids more than made up for the drop that we saw in gas. We gained 2,589 barrels a day, up from 41,250 barrels a day of total liquids in Q3 to 43,839 in Q4. And that's a 6.3% where on an equivalent basis a 15.5 million day increase from Q3. And as might be expected, the Permian represents the lion's share of our fourth quarter liquids, representing 42% of the total followed by the Gulf Coast at 30% and the Mid-Continent at 28%. Well, the driver for our total liquids growth was our Permian program, which, with our increased activity, grew 1,958 total barrels a day from Q3. 1,400 of that was oil. We also continued our focus on liquids-rich gas where total NGLs up 1,858 barrels a day from Q3, most of this coming from the Mid-Continent and Permian. The end result, as we look at Q4 compared to Q3, is that we were up on an equivalent basis and continued to increase our product mix towards liquids. We're up 4.5 million a day for the quarter, and with our total company oil and natural gas liquid ratio at 41.3%, in Q3, we bumped it to 43.5% in Q4. Year-over-year comparisons as compared to Q4, we saw nice production gains in both gas and oil and natural gas liquids. Our Q4 '10 gas production of 341.5 million a day was up $11.5 million a day or 3% from Q4 '09. And our fourth quarter 2010 combined oil and NGL production of 43,839 barrels a day was up a respectful 91% from our Q4 '09 average. Over the last 12 month, we've realized nice equivalent production gains in each of our core areas. As compared to Q4 '09, our fourth quarter Mid-Continent equivalent production of 271 million a day is up 65 million a day or 32% from Q4 '09. Our Permian production of 182 million a day was up 38 million a day or 26% in Q4 '09. And our Gulf Coast production of 145 million a day was also up 38 million a day or 35% from Q4 '09. So nice year-over-year production growth in each of our core areas. Cana continues to be a strong contributor to our bottom line. We ended the year with Cana equivalent production an exit rate in Q4 just shy of 100 million a day. That's up threefold from our Q4 '09 exit rate of 33 million a day and was pretty darn close to where we had told you the beginning of last year where we hope Cana would be at the end of 2010. So the bottom line to our '10 production was that we had a great year. Despite property sales, which impacted our reported figures by 2 million a day, our reported 2010 average net daily equivalent production of 596 million a day was up 29% from our '09 reported average of 463 million a day and well surpassed our beginning year guidance of 520 million to 540 million. Our production growth was a direct result of the increase in successful drawing in each one of our core areas. And with our emphasis on oil and liquid-rich gas, we not only significantly grew production, but we also continue to shift our product mix more towards liquids as seen in the percent of liquids that represented our production in 2010 at 39% versus what we reported in '09 at 30%. So we gained nine points in liquids. Looking into 2011, you may recall during our last call that our early modeling for '11 predicted a 2% to 10% increase of production for 2011. We updated our model to incorporate our year-end base property forecast, our '11 budget, and just recently, the estimated impact of the weather-related shut-ins that we just experienced here in early February. The extremely cold weather pattern that hit most of the U.S. in beginning of February hit us fairly hard, in particular in the Permian, where we experienced numerous shut-ins as a result of freeze-offs, plant shut-ins and rolling blackouts. In addition to well shut-ins, the weather temporarily shut down or delayed a number of our frac jobs that were slated for that first week of February. The data that still needs to come in, we are projecting that the weather will negatively impact Q1 net equivalent production by about 10 million to 15 million a day. And taking this into account, along with our 2010 and early 2011 property sales which took about 5 million a day off of our '11 books, we're projecting Q1 '11 now to be in the range of 582 million to 602 million. Even with the impact of whether and property sales, our updated '11 model doesn't really depart from our previous guidance that we gave you last call for 2011, and it's basically predicting a continuation of the same story we've seen over the last year. Production adds from the Permian and the Mid-Continent are forecasted to more than offset any declines that we may see in our shorter out of our key Gulf Coast production. Despite our current forecast for Gulf Coast properties to drop from actual levels of 150 million a day in Q4 '10 to levels of 120 million to 130 million a day in Q4 '11, our updated model projects '11 equivalent production to fall in the range of 615 million to 645 million a day, with our midpoint being up 6% from 2010. In essence, our updated guidance just tightens our previous band of expected production growth around the same midpoint, even when taking into account the loss of 5 million to 7 million a day of annualized 2011 production due to property sales and the impact of weather on our production volumes in Q1. With the majority of our '11 budget allocated to our oil-rich Permian and liquid-rich gas programs, we're also modeling a continued increase in the percent of our production associated with liquids to 44% for 2011. That would be up five percentage points from the 39% we posted in 2010. In a nutshell, we expect much of the same story in '11, increased activity in our core oil and liquid-rich gas plays, resulting in continued production growth for our company. On Slide 24, you'll see a quick slide talking about our production operations group. The group put together a very solid year for us in 2010. With continued focus on our base properties, the group did a great job optimizing production and maximizing NOI, all the while putting about $44 million of exploitation capital to work. About half of the capital went towards recompletion activity in the Permian and the Mid-Continent, with the remainder going to a variety of work-over, left facility and saltwater disposal projects throughout all of our core areas, as well as a handful of operated and non-operated infill drilling projects that we performed in West Texas and Kansas. In all, the group performed over 390 projects during 2010. They met our expected production goals, and our look back economics confirmed that are exploitation capital was spent wisely. Most importantly, however, I want to note that we ended the year on a very safe note, with over 200 field employees excelling at their jobs with no lost time accidents during the year. In December, the production group finalized for 2011 planning process. During '11, we'll remain focused on our three simple objectives: Increasing our net operating income by optimizing production and controlling our cost; effectively deploy our exploitation capital; and most importantly, improve our operating capabilities in the field. We put together another solid inventory of exploitation projects for '11. During the planning process, we identified over 600 projects, corresponding to more than $95 million worth of possible activity. We call those projects and high-graded them and have come up with an '11 budget of $60 million to $70 million. The final list includes about 475 projects that encompass a wide variety of activities, artificial lift, recompletions, gathering, compression, SWD, workovers, and again, a handful of low-risk infill drilling and a lot of other projects. We anticipate a fairly evenly split in the capital between the Permian and Mid-Continent, with most of the dollars slated for recompletions, saltwater disposal projects and artificial lift. On Slide 25, you'll see a chart which looks at our lifting costs, and I'll give you a few words about LOE before touching on our drilling and completion costs. A look at our financial shows Q4 LOE coming in around $0.98 per Mcfe. That's just below the midpoint of the guidance we gave you for the quarter of $0.90 to $1.10. As we mentioned in our last call, over the last half of 2010, we saw an increase in expenses due really to three items: First, we're fairly active changing out lift designer, installing sub pumps on our new wells in an effort to attain peak rate. Most of this transpired in the Permian basin. Secondly, we put some extra money to work improving our lease maintenance and appearance. And thirdly, with our increased new well activity, our SWD costs went up as a result of produced load water disposal. So with that said, our 2010 overall lifting cost came in at $0.89 an Mcfe, but that was still down 15% from our 2009 average of $1.05. We're expecting the bit of a cost increase to incur coming into 2011. And as such, we provided guidance for '11 lifting cost for them to fall in the range of $0.95 to $1.15. We continue to see constant increases in our drilling and completion costs, especially on the completion side. Over the last year, we've seen our fracture stimulation cost go up anywhere from 5% to over 100%. We've worked hard to alter our frac design where we can to optimize results while controlling costs. As an example, in Cana, we reduced the size of our jobs and have kept our total frac cost increase to a modest 5% over the last year. In the Permian, however, we see anywhere from 25% to over 100% cost increases over the last year, with the bigger increases seen when we've increased our job size. There were a couple of questions last call about frac horsepower and availability. Well, frac horsepower and crews continue to be in high demand, and as a result, we have approximately 18 wells waiting on frac, a dozen or so in Cana and the remainder in the Permian. That said, we are seeing the beginning signs of fleet availability and the possibility that market maybe loosening up, especially in the Permian. And we've heard rumblings from five to six different service providers that more horsepower is right around the corner. As such, we're hopeful we'll be able to make up some ground on our backlog during Q2 and Q3. We've seen cost pressure and other items as well. Since Q3 '10, our average Mid-Continent and Gulf Coast day rates have gone up 12%. In the Permian, they've gone up 23%. We've seen increases in directional costs, cementing, bits, fuel, mud, mob and rentals. Those increases have gone up anywhere from 10% to 50% since Q3. To fight these increases, we continue in each of our programs to focus on improving our operating efficiencies and challenging our program design. And as a result, since the third quarter of last year, our total well cost have increased only 5% to 15%. As an example, our generic Cana AFE is currently running around $8.4 million. That's up 5% since Q3. And in the Permian, our current AFE for a 6,000-foot vertical padded boundary well is running around $1.9 million. Again, that's up 5% from Q3, and an 8,000 New Mexico Bone Spring horizontal well, a lateral well that's running around $4.3 million. That's up 15% since Q3. So we're still seeing cost increases. We're minimizing them where we can through program and cost efficiencies. So to wrap things up, we closed out on a very successful 2010, and we're projecting continued production growth for 2011, and we'll continue our focus here in '11 to keep costs in check and ensure the profitability of our programs. So with that, I'll turn the call over to Paul.

Thank you, Joe. As a result of some pretty heavy lifting by both our exploration and operations groups, I have some, what I think are impressive financial results to recap for you. With higher oil prices and substantially higher production, we had oil and gas sales of a little over $1.5 billion, of which $1.2 billion hit the EBITDA line after adjusting for working capital and things like that, we had $1.1 billion of cash flow. And from there, we had $575 million of very high-quality earnings or $6.70 a share. As has been our history, we reinvested the bulk of our cash flow in exploration and development, and of course, had very good results. Since we look to 2011, we've mentioned -- we expect our capital expenditures to be $1.2 billion to $1.4 billion, and I do believe that any reasonable estimates of our cash flow will coincide with that number. We have a little bit of a cushion though because we walk into the year with $114 million of cash on our balance sheet, and the only debt that we have remaining is our $350 million of senior notes due in 2017. So by any measure, investment-grade credit statistics, which we shall list for you on our Slide 27, 12% debt-to-cap ratio. Our EBITDA is 3.5x our debt. Operationally, we've covered a lot of things. The short version is we grew our production 29% and our proved reserves 23%. Good finding costs, higher reserve replacement ratios, and we did not do it with PUDs, obviously. Our PUD percentage is the same as it was at the end of last year, 23%. In absolute numbers, PUDs were up a little bit, but no more than we increased our proved developed reserves. Of our PUDs, still half of them are in our Riley Ridge project, which we hope will be on production by the end of '11, if not soon thereafter, and we're only carrying about 200 BEs of PUDs in Cana at this point. Production-wise, as Joe mentioned, our best estimate at this time is 615 million to 645 million a day. So obviously, we don't think we can repeat the type of growth that we had in 2010, but you have to remember that a lot of that increase was driven by those wells in the Gulf Coast, which of course represent the best wells any of us have ever seen in our careers. So that's a very tough act to follow in terms of production volume growth, but it's not unreasonable to expect that our reserve growth could continue along a pace that we saw in 2010. The last page just outlines, for completeness' sake, our hedge position. The short version there is that we wish we had more gas swapped. We only have 20 million a day, but at the time we were doing this, we were unwilling to swap into a market that we thought represented a low price of $5. Of course, now here we are $1 lower. So in hindsight, it's pretty easy to say we wish we had fetched more gas and maybe a little less oil. The remainder of what you see on our website are things that we require to show you because we use some non-GAAP terms. So you'll see definitions of EBITDA, debt-to-cap calculations, cash flow from operations and finding development costs. With that, operator, we would be very happy to begin to entertain questions.

[Operator Instructions] And your first question comes from the line of Brian Lively. [Tudor, Pickering, Holt & Co.] Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Just looking for some color on your inventory position in the Permian. Specifically, have you guys counted the number of high-confidence locations you have in the Bone Spring, and if possible, the Wolfcamp?

Brian, this is Tom. Of course, the Bone Spring is lots of different targets. So I'm probably not going to answer the question you asked, but in our second Bone Spring play in Eddy and Lea County, when we count, we get somewhere with our current land position with our currently mapped targets in generally the second and third Bone Spring at somewhere, I would say, between 75 and 100 locations. But that is a constantly changing number, and in that fairway in particular, we had some objectives in the first Bone Spring that we're very excited about that we haven't tested yet, and it overlays our entire position. So that's what we count today. In the third Bone Spring horizontal oil play down in Ward, Reeves, Winkler County, in that fairway map we show in our website, that would be southeastern edge of the fairway. We have about 150 gross locations yet to drill in that project in the third Bone Spring oil. And then everywhere in between, we have lots and lots of inventory. I mean, I -- yes, and our White City play in Eddy County, we have a second Bone Spring oil play that we really haven't even talked much about. We drilled the well last fall that looks very encouraging to us. It's an exact look-alike to our second Bone Spring play in Eddy and Lea County to the north. The gas oil ratio is a little higher there, but it's -- their oil wells and we have an inventory there in our current lease position of about 80 to 85 locations. So, Brian, we don't typically count locations, but nonetheless, we have a multiyear inventory at our current run rate. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: I was just trying to get a sense of the breadth of opportunity, and those are net locations?

Those are typically gross locations, and our working interests vary typically there between 16% and 100% in those plays. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: One thing that maybe not surprising but the repeatability so far, especially in the Eddy, Lea County area, has that surprised you guys? Maybe in the same context, could you discuss ranges of ultimate recoveries, maybe P10 to P90 type estimates if you have them?

Your first question has not surprised us. I think I would be disingenuous if I didn't say, yes, we've been pleasantly surprised by our results. When we marched into that play, in Eddy and Lea County and the second Bone Spring, our initial model was built around 250,000 to 300,000 barrels recovery per well, and we were talking about initial production rates of about 250 barrels per day. And that was based upon no production history. There were very few horizontal wells drilled in that trend. So, yes, we've been pleasantly surprised by our model. Our current model for a go-forward well in that trend is a well that will produce ultimately 570,000 barrels of oil at Mboe, of which 400,000 barrels of that is oil and 170,000 Mboe is gas. And we'll produce 600 barrels of oil on average in its first 30 days. As you can see from the results we've reported, our averages are actually north of that. So I don't have in front me what our P10 is, but we drilled some wells that have averaged over 1,000 barrels a day and are upwards of at or near 1 million barrel well, so it's a wonderful trend.

I think one of the things -- this is Mick -- is that it's nice to talk about these statistics, but that's something that you wave -- in that area that we're talking about, you can wave your hand over in a 10th of a second. And if you've got fast car, it will take you half a day to drive across it or something. I mean it's a big area. And so we have a few -- we have data points in there that we're interested in, but it's a huge area. Offsetting that, though, is the fact that we have a lot of competition out there and very capable competition. And so understanding the area is going to probably happen a little quicker than it might in some other places. And so we'll come to an understanding of that. In terms of your question about how much inventory do we have, that's a tough question, but we've looked at it and I don't really look at location. We generated out of locations, but we did a little study and we tried to understand how many things that we have control of geologically and all that, that might drill. It came up to something like $3 billion of future drilling, not counting what we're going to do in '11. So we have a fairly rich inventory of things to do, and there wasn't a lot of hope and wish in that. Those are things that we'd like to get done. And I'd also tell you that one of the challenges in all of this is that that's a very active area. And so all the resources that it takes to get these wells drilled and picked up the pace, it's going to be tough. We're adding rigs, but other people are adding rigs. And so you have to have -- and these are mostly horizontal wells or almost all are horizontal wells. And so it takes certain people and certain kinds of equipment and everything we're all competing for that, not to mention the stimulation delays. So anyway, I guess I've complicated it a little bit, but I want to just give you a flavor for that's a big area, it has big potential, we recognize it. It's going to take us a few years to get through it, and it's unfolding in terms of the information as we go. Tom mentioned the multiple play aspect. That's an important piece of what we're talking about. There is a lot. We not only do we not understand where the thing goes laterally or across the geography, but it has potential to extend vertically into other zones. So, anyway, I just wanted to confuse the issue a little bit by giving you that information. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: What was the future development costs in the PV-10 calculation?

Brian, we'll quickly trying to dive into future development embedded in the PV10, Jim, is what he's asking.

I believe it's $427 million.

And your next question comes from the line of Gil Yang. [Bank of America Merrill Lynch]

Could you talk about in Culberson County, in that area, what the availability of water is for frac-ing? Is that potentially going to be a problem?

Well, it's a challenge. This is Tom. We're currently buying water off ranchers and then we're trucking and disposing water. I anticipate as we go forward in development, we will find alternative water supplies, how the drilling water wells and I'm sure we'll have some disposal wells. Joe, do you want to add to that?

The only thing I would add is we're looking at other zones to drill for freshwater.

So would the water costs rise or fall if you drill the well versus buying, the purchases you're doing now?

I'm going to say, we wouldn't drill the well unless it fell. I mean, we will drill the well for one or two reasons just because we have availability that wouldn't have otherwise and because its cheaper on a barrel basis. And I would anticipate the cost would fall for drilling a water well.

I would agree.

Are there difficulties getting permits to do that?

Permitting generally is not the challenge in Texas and it has been in New Mexico. So when we look at our obstacles in Culberson County, I'll say permitting is not one of them.

You talked a lot about cost efficiencies to minimize the impact of inflation. When you do that, are you able to do that without an impact to EUR? Or is there some trade off that you sometimes have to make?

No, there would be no impact on EUR. What we're talking about during like in Cana different techniques for drilling, as time shave down our drilling days. On the completion side, it's always a balancing act to juggle the cost of your completion with the results from your completion. And we've been able to alter our Cana practice on such that we're seen as good or not better type of results from the frac.

For 2011, your guidance has been spend your cash flow basically. In 2010, that's where your goal was, yet you underspend cash flow by about $100 million or so. Was there some limitation that caused you to do that? Or is your policy a little bit more conservative on the spending side and so maybe you're expecting cash flow for 2011 to be a little higher than this?

You're giving us way too much credit for being planners. We don't have a shortage of money. And if we borrow a little money, we can borrow money and we're still probably the lowest levered outfit, or one of them at least, in our whole peer group. So what we start off doing is do as many projects, get as much done that gets us the kind of return we can get and just go as fast and as far as we can. And so there's a lot of impediments to getting that done. But it's not like we're keeping track of how much we're spending. We're keeping track of what the returns are and trying to maximize how much capital we get down at a good rate of return. So right now, the guess is that it's going to be something around cash flow, like it was last year, and we'll see what happens.

But in that context, I mean you clearly have a lot of good projects to drill, and so you, in principle you, could have spent a lot more money, but something held you back, and was that the availability of fracs, drilling equipment?

Gil, it's Paul. I'll take a stab at this. We recognize we're not very good at forecasting prices. So particularly last year, we walked in fairly cautious, if you will, in terms of what would happen to prices as the year unfolded. We had a fairly recent memory of some much lower oil prices. And so we only had four rigs running in the Permian in the first half of the year. So as we gain confidence in where the price of oil was and that it might stay there, then we added rigs. And so we spent substantially more in the second half than we did in the first half. But, frankly, we were just unable to catch up with what turned out to be more cash flow than we thought we would have.

To me, the cash flow is nice, but when that oil price went up, that rate of return went up. And so more projects became available to us, we tried to get to them, and we just couldn't accelerate our activity. And this year, Tom, what do you have planned for rigs?

Well, at beginning of the year, we're saying 16 Permian rigs, and we're now at 17. So we'll probably have between eight to nine in Cana, one to three in the Gulf Coast. So we'll be 25 to 30 rigs.

If nothing else, it's not just drilling rigs and all that. A lot of our activity is operated, most of it is. And we have the staff supervision for these things and so just trying to grow the program as fast as we'd like to in the Permian is going to be a real challenge because everybody that's out there has good economics on their high liquid content opportunities, and they're trying to pick up the pace at the same time.

And just to clarify for your forecast, what are the commodity prices you are using?

Gil, we don't have a fixed forecast for commodity prices, probably a range around $95 oil and $4.55 gas, something in that range. You get pretty close to that $1.3 billion.

And your next question comes from the line of Nick Pope. [Dahlman Rose & COmpany] Nicholas Pope - Dahlman Rose & Company, LLC: The freeze off that you're talking about, is that kind of company-wide, or is there some specific areas where you're seeing the bigger impacts there?

The biggest impact -- this is Joe -- was in the Permian. And I think I combined total Permian and Mid-Continent impact on just February. Our numbers are running around 35-ish million a day, and that's a preliminary estimate. Of that, about 9 million a day was coming out of Mid-Continent and the rest was coming from the Permian. And it was just a combination of things. Your downstream plant shutting in on you, you can't produce. We'd get a well up and running, and all of a sudden, it'd be part of a rolling blackout, and all of a sudden it shut in and now throws off. So it's just a combination of things. And it had a big impact on us, and I'm almost certain it's going to have a big impact on the other Permian players as well. Nicholas Pope - Dahlman Rose & Company, LLC: And then I guess as you look at kind of where the pricing is up, pricing is in that cushion and for West Texas Intermediate. Can you talk a little bit about I guess what you are looking at in terms of both Permian Mid-Continent oil and the ability to get the production out and the ability to get kind of a pricing you want on that oil right now just thinking of the marketing aspect.

A couple of things. Total company production of 25,000 to 30,000 barrels a day were not a dominant part of any pipeline or market. The bulk of our oil production is priced off of WTI and NYMEX. Do we wish we had some more priced off of LLS? Yes, we do, but it's just a function of where we operate. Nicholas Pope - Dahlman Rose & Company, LLC: And just in terms of like pipeline capacity and get it out, Do you all feel pretty comfortable that in terms of the volumes and everything else going into cushion over the next year that you are going to be able to get all of your oil to market?

This is Joe. I would say anywhere we've seen the delay, it hasn't been the result of that. Where we've seen more of our problems getting oil off location is right when we turn them on and we're making a heck a lot of oil and we're trying to have enough trucks to keep up with us, to meet that higher volume. So as a result last few months, we've seen a little bit of oil volumes that were produced but not sold. As far as getting into marketplace, we have not seen any significant issues in that regard, and at this moment, we don't anticipate that we will. I'll touch a little bit on what Paul mentioned too about Louisiana Sweet, about 20% of our oil has a contract that is based on WTI price, and we'll get a kicker for a Louisiana Sweet differential. Right now, for March, it looks like that kicker will equate to about $7.05 as far as a premium on about 20% of our total oil. I wish it was a little bit better, but we had locked in a portion of that when we started to see the differential pick up a bit and all that goes away here in May. Nicholas Pope - Dahlman Rose & Company, LLC: Related to the PV-10, do you have a split of like what the PV-10 was on the PUD component of your reserves?

While Mark is looking -- this is Paul -- I'd tell you we did plan to file our 10-K by next Friday. All this stuff will be more readily available to you.

And your next question comes from the line of Ronny Eisemann. Ronny Eisemann - JP Morgan Chase & Co: I just had a quick question on Slide 12. You showed the Wolfcamp statistics. Do you have some more preliminary data for what you're calling the Penn Shale?

Well, this is Tom. We do. We've taken core and log data on the Penn Shale. We don't have a table for it. I can say the Penn Shale would stack up. It's not as thick. And it's also variable. So it's kind of hard to quote averages. But we typically see the Cisco/Canyon, where we have logged with modern gas shale logs, where we have core, we typically see it as competing with these types of source rocks. We would be typically north of -- somewhere around 100 Bcf a section. It's got good organic content, good porocity. And then, of course, as I said, the recovery factor is a big wild card. And we definitely see it as an independent objective to these targets. Ronny Eisemann - JP Morgan Chase & Co: So it's relatively comparable to what you're showing for the Wolfcamp?

Well, it's not as thick. But I would say yes, it's comparable to the Wolfcamp in terms of source rock quality. One of the things that, Ronny, that we haven't done and the reason we're not kind of beating the drum more loudly on this Cisco/Canyon, we don't have a modern horizontal stimulation. We have drilled a number of vertical wells in and around White City where we have either used it as primary objective or recompletions, and we're very, very encouraged. But the next thing we need to do is get a lateral down and put a modern stimulation on it. And what I mean by modern, the one horizontal well we did drill in the Cisco/Canyon, we drilled in the wrong orientation. We only had 700,000 pounds of profits in place. Today, if we were to drill that well, we'd reorient it, and we would put five times that amount of profit in that stimulation. And we're seeing that to make a huge difference. And so we are really, really encouraged and excited by this Penn Shale or Cisco/Canyon, as we call it, but we don't have the kind of results that we did with Wolfcamp. One of the reasons we're focusing on Wolfcamp and not Avalon is some of these leases are only held to depth drill. And so we're kind of focusing on deeper objectives. Just in terms of if you look at the landscape out here, in our White City-Culberson, Avalon's at about 5,700 feet, Wolfcamp is at about 9,500 feet and Cisco/Canyon is about 10,500 feet. So it's not -- for some in this area, I think we're going to have all three of those three objectives stacked. And we don't know the spacing yet. We really have a lot that we don't know.

Hey, Nick. If you're still online, it's Mark Burford. Just to answer your proved and developed PV-10 question, of our $3.6 billion of PV-10 pretax, $206 million of that is proved and developed reserves. $206 million of PV-10 pretax.

And your next question comes from the line of Derrick Whitfield.

Tom, Joe, could you share with us any additional color on the variability of your Wolfcamp test results in terms of average production and gas-to-oil ratios?

This is Tom. We have a pretty good average out here. I can tell you that the condensate yields vary from 20 to 80 barrels per million on the wells we've drilled. And one of the things, just an editorial comment, in this part of the world, these yields can vary significantly. And generally, basin, White and Delaware Basin, as you go from west to east, you get gassy to more oily. We've yet to test. We have drilled but haven't completed yet. On the map we show, as you go further east, we have some Wolfcamp tests that haven't completed and haven't flowed back. We expect the results there to be significantly oilier based on results we have for vertical wells. And then our EURs on an equivalent basis, they vary from 2.5 to 7.5. So we have some pretty good variance. Some of that variance is wellbore orientation. Some of it is local areas drill. Some of it is we've been tuning up our completions. So overall, I'd say our averages are kind of what we think are what we're going to go by.

In the White City area, Tom, you had mentioned earlier that you guys had drilled some really good wells back last fall. Have you drilled anything since in the second Bone Spring?

No, we drilled one re-entry well there in second Bone Spring. It was a well called the Burn. As I said, it was very encouraging result. It came online at 600 barrels of oil per day. It's a little gassier. Up in Eddy and Lea County, our gas-oil ratios go between 1,000 and 3,000. That well had a gas-oil ratio of 6,000. But it's still an oil well from the dollar-priced oil. The reason we're not out there drilling more wells is we just have a lot to do, and it's going to be -- we're going to be adding a rig up in our 2011 program here shortly. That will be dedicated to drilling those wells.

And then where do you guys stand on 3D seismic activities in the lower Abo?

Well, we recorded and have processed a 3D seismic survey over our Caprock [ph] [1:09:38] project in the Abo. We're in the process of interpreting it. We shot it because of a curiosity as to whether we can see that pinch-out edge. I'll say that we're encouraged by what we saw, at least locally. We think we see some things that are consistent with the subsurface. And we're looking to use that tool to extend the trend. So, so far so good. But it's a big trend. If you go east from our Abo play, and I've seen many, many different maps on that and most of them are competitors' websites. And that trend starts to branch out to be 100 miles tall. So we're trying to use seismic data to dial that in a little bit.

And then moving over to the Gulf Coast. What's the implied success rate behind your year-over-year production guidance? Are you guys assuming that historical cost 68%?

This is Joe. I guess I don't understand your question. Are you saying when we went ahead and forecasted something, did it turn out as we forecasted?

No. The Gulf Coast area where you guys had provided guidance for 2011, it being down year-over-year, what was the success rate behind your drilling program that you're projecting forward?

As far as -- there's two components there. You have your base properties, which are projected to climb fairly significantly in 2011. And then we augment that with risk production profiles from the new drills.

Derrick, this is Tom. I'll say that for -- we had a lot of different things going on in the Gulf Coast right now. We have a rig that's kind of focused on drilling what I would call base hits. Based on the wells we have drilled, we've kind of derisked a number of smaller targets. And those are -- when I say smaller targets, I mean, three to eight Bcf equivalent targets, very nice production rates but just smaller ultimate recoveries. Today, for some of those derisked targets, we're probably on 85% chance of success. And then we have another layer of things that look like what we've done and yet they may be a little further away, maybe a little deeper section. That would be typically about a 70% chance of success, and that's kind of our historical average on trend. And then we have some things that are a little higher potential that are fairly wild. And there we'll probably predrill, running 40% to 50% chance of success. So we're modeling it like it has a greater chance of being a dry hole than producer. But our overall trend average, if you look at the 106 or 109 wells we've drilled, there's about 65% to 70% wells that we drill we've completed.

And your next question comes from the line of Mitch Wurschmidt.

All my questions were asked, but I just want to get a better sense of in the White City sort of area, the area you outlined for the Wolfcamp, how many rigs are you dedicating sort of to the Wolfcamp program? Or it sounds like you'll be testing a few different things. Can you kind of lay that out a little bit?

Yes, we'll have two to three rigs out there when we get fully ramped up in 2011. And that would White City Culberson County, which is really subject to our results and all of the things we typically cite. We have some lease expirations we're managing, and that's got one rig busy just drilling things to preserve our leasehold. We have some marketing issues we're trying to solve, but we are planning to have two to three rigs working out there.

And does that look -- you guys outlined a certain area, but where is the Wolfcamp? Just the aerial extent of it throughout the Delaware Basin. Is it sort of either further to the north in order to get into your Central Eddy area or is it just sort of more localized to that area?

Well, the Wolfcamp produces all over the basin. And you're really talking about what [indiscernible] [1:13:55] produces. In the deep Delaware Basin, where we would consider to be an unconventional reservoir where we would have regional extent, the [indiscernible] [1:14:07] that would be associated with that would certainly encompass that dash line that's shown in the map in our website. So it's a broad area. Now it's not going to be productive everywhere. You have a lot of clastic input. There's a fair amount of variability. You're going to have differing yields. I mean, so we see in general sense that the trend encompasses that dashed area. But is this all going to be productive? Assuredly not.

And I guess just going back to an earlier question, thinking about -- I mean, you guys are obviously opportunity rich here. Is sort of 16, 17 rigs in the Permian, I mean, how do you think about walking that up? Is it just trying to manage, I guess, the operations? Given, obviously, you guys have been ramping up quite aggressively, how much more could you, I guess, push it if you really wanted to?

Mitch, this is Tom. I'll take a stab at that and then Mick may want to comment on it. We are accelerating oil to the extent we can. I mean, so everywhere we can accelerate oil, we are pedal to the floor on that. And we have some limitations. And we talked about that, but I want to just underscore them. A limitation is our own organization. This is not a mining operation. These are geoscience projects that take careful attention to detail. And we have found that when we try to turn this into just a paint-this program with too broad a brush, we start really wasting capital and drive our returns down. So to optimize our rate of return, we're going to do the kind of detail that's led us to this point. We didn't get here by being sloppy. And we're not going to go forward by being sloppy. In New Mexico, there is a limitation. Permits are a problem. I'm sure you're hearing that from many Permian operators on Federal lands. The BOM is thinly staffed and backlogged with everybody ramping up activity. And then certainly, stimulation is a challenge we're having to manage. That said, we're going to be at 17 rigs here soon, and we're going to accelerate everything we can. Mick, do you want to add to that?

That's right. I'm going to bore you with what we usually wind up saying during one of these things again. And that is, we're driven by rate of return, not production increases, not reserve increases and all of that. We want to get increases in production because it relates to our cash flow. And we want to get as much production increase and cash flow in the door as we can. But at the end of the day, we only have one criteria, and it's done on a well-by-well basis. And that's what's that return. So it depends on how that goes along. And then the other limitation is, so, low gas prices could influence us. If LPG sort of go down, that might influence some plays. There's a whole bunch of things out there that are going to do it. But as we go along, we're going to go just as fast as we can organizationally and try to maintain our high rate of return or get the best rates of return we can on our capital employed, whether it's our cash flow or borrowings or whatever. And I just want to reinforce that idea, that our biggest limitation probably is going to be organization.

And your next question comes from the line of Jeff Robertson.

Can you talk of the $200 million you all are going to spend on some of these emerging plays in the Permian? Do you have a rough allocation as to how much will go toward the Wolfcamp or the Cisco/Canyon or the Avalon?

Yes, Jeff. This is Tom. The bulk of that is going to be Wolfcamp. We're testing the Wolfcamp throughout this area. And we like the Avalon. We tend to kind of downplay the Avalon. The Avalon is prospective over almost all of that 125,000 acres. The issue with the Avalon is when we model it -- and again, we don't have all the data that some of our competitors do, but when we model it, it just doesn't compete with some of our other projects including the Wolfcamp. And we're watching activity of others, trying to learn everything we can. Right now, I'd say the bulk of that is going to be Wolfcamp capital. And that's subject to change. If we get some new information that leads us to be more bullish on the Avalon, then we could be drilling Avalon wells. And then we're still really interested in our own results by doing a modern completion on the Cisco/Canyon lateral. Right now, though, I'd say the bulk of that unconventional is going to be Wolfcamp.

You will see the Avalon most of the time when you drill the Wolfcamp well, is that correct?

Oh, yes. No, the Wolfcamp is below the Avalon, so you go through it. And Jeff, this is more detail probably than you want, but in Cana where we've drilled well over 100-and-some-odd wells, you go two miles and it changes rapidly. Now we're looking at a huge, huge area where we don't even have one well per township. And the yields are going to change, the rock quality is going to change, the degree of natural fracturing is going to change. And so as we get a little more data here, this thing is going to get much more complex. Our contours right now are nice and smooth. They are going to tighten up a little bit.

And for the Cisco/Canyon, do you have a lot of penetrations either to that or to some of the formations deeper out there that'll help you get control over at least what the thickness is and what the [indiscernible] [1:20:01] are?

We do. One of the nice things out here is there's been a lot of deep drilling in the basin. And then one of the things -- I didn't give any detail on this, but we have 15 Cisco/Canyon-Wolfcamp vertical wells that we have completed in our White City area. And so for at least vertically, we've got some data, and we're hoping to extend that horizontally. And others are doing the same, but we're not the only one. People talk about the Penn Shale. This is throwing [indiscernible] [1:20:32] in what we're talking about.

But I guess a couple of years ago when people were testing the Barnett and Woodford out there and trying to complete it, which is, I think, deeper, do the efforts in that help at all in trying to devise a completion technique for the Cisco/Canyon?

Well, if they did, that information didn't make it toward to us. Now, of course, we weren't out there. We were in the middle of that. But most of our advances have come from what's going on in Cana.

And your next question comes from the line of Joe Magner [ph] [1:21:07].

Scott Firestone [ph] [1:21:12] sitting in for Joe. Devon had some -- released some info on the Cana downspacing part that they had. And they were referencing mini EURs of eight BEs and eight to 10 wells per section. And we're hoping you could maybe provide some insight on how you're going to book reserves in that play.

I'll probably take a stab at that because Gary Abbott is our guy that -- he's not in the call today. He's in charge of how we book our reserves. At this point, we booked direct offsets where we have geologic information to do that. So it might be one well, it might be two wells depending on if we own the acreage on the offset or how it works. And then when we're talking about the core area, so we've done that. That's where we're at. And in terms of what happens in the future, to book beyond that, if we understand the SEC regulations, we have to rely on a reliable technology criteria that is supposed to be field tested. What's happening here is that Devon has -- they're ahead of us in how they look at -- we're looking at the same data, or I think that we're looking at the same data, and we're looking at it the same way. But what's happened is, is that in the whole process of doing that, they're more experienced and they're ahead of us, and so they got the answer a little quicker than we did. I feel pretty good that we're going to arrive at the same answer in terms of spacing and what's bookable within -- we'll be close, I would guess. It's just going to take us a little longer to get through that SEC part of it that says this is what we think the answer is. Now we could do meet, too, on it, but our guy that books the reserves has been a little -- he'd be a little nervous about explaining to the SEC that it's how we got there. So you're going to have to put up with us taking a little bit longer to figure this out. In no way do I want to imply every -- we think Devon's done a heck of a job. And everything that we see out there where we're partners with them, they did a great job and we have no disagreements. So we'll see how this all works out, but we've got to get our own answer and we're a little slower than they are.

Another question on breakeven cost. Maybe shed some insight on the various plays, what your stress case price level might be.

This is Tom. We run a stress case on every investment we make. And our current stress case is a $3.50 NYMEX gas and $45 NYMEX oil. And we subtract local market deducts from that, and we hold that flat through the life of the well. So that would be a received price currently for most of our Mid-Continent and Permian of somewhere $3, $3.10 for gas and between $40 and $45 for oil. And then for natural gas liquids, we'll take 45% of that oil price. So we're somewhere between $20 and $25 a barrel for NGL. So that's our stress case. We typically will ask that our investments will get cost of capital or better at that stress case. In fact, we'll actually add a little windage to that just to pay for organization. And that's not a price case that we make our decision on, but we have a lot of opportunity company-wide, and we rank all of it side by side. We look at it at current strip pricing. We look at it at that catastrophic downside and then several price falls in between. But we'd like to see, at least at that the $3.50, $45 NYMEX, that our investments at least get cost of capital. Now that doesn't answer your question on breakeven price, but I don't have that in front of me on our various plays.

Just one last thing. On the $3 billion referenced in future development, the second and third Bone Spring, does that apply to all the Permian plays or...

What that is, well, I'll let Mark explain it a little bit. Mark?

Scott, you know it's really rough -- [indiscernible] [1:25:38] too much weight on that, Scott. But we trying to incorporate some rough, real rough estimates on what we could drill in the second and third Bone Spring both in New Mexico and West Texas, put a real swag number of what we could drill on the Wolfcamp for next several years. Or some swag number on Wolfcamp as well. So they're very loose number, Scott, but we put some numbers on the acreage and spacing and...

Well, it was it was not quite as swag as all of that -- based on what was mapped geologically. And so it was mapped and owned acreage and things they felt good about drilling. So it's going to depend some on product pricing, how much the gas helps the liquids. But that wasn't a maximum number. That really wound up being one of the more conservative side of what we saw out there.

Yes. This is Tom. I think one of the nice things, we're multiplay based, and I wouldn't put too much weight one way or another on that number. We have a lot of potential in a lot of zones that we haven't fully developed. So...

That aren't in that number.

...That aren't that number, yes.

I don't think Tom is worried about that number being too big. He is worried about the fact that it's a conservative number.

Yes. What I'm really worried about is getting the best returns we can out of our program. Inventory is not in our top concerns. It's high grading, exploiting efficiently, understanding our ultimate spacing early so we can get those efficiencies that we've been asked about. It's a really wonderful basin. And our position in the Permian, sometimes we just want to pinch ourselves for the great strategic vision Mick showed in the acquisition we did years ago.

And your next question comes from the line of David Deckelbaum.

I'll make it quick. I guess we've had a lot of answers today. But I guess lastly, just on the Permian, two questions there. One is, in going up to 16, potentially 17, 18 rigs, where are the incremental rigs? You're going off 12 right now. And I guess adding on to that, how would you guys characterize some of the infrastructure restrictions there? I know you said some of the limitation is internal. But certainly, in areas like the Bone Spring and Avalon and some of the more unconventional places, how do you guys view the takeaway capacity restrictions there right now?

David, this is Tom. I am going to do this off the top of my head. I don't have our rig schedule in front of me, but we're going to add a rig this year in White City. That's addition to what we're doing now. They will be drilling these horizontal oil wells. We're going to add a rig in our third Bone Spring play down in Ward County, drilling horizontal oil wells. We'll have one or two additional rigs in the White City-Culberson area, drilling unconventional. And then we'll probably have at least one additional rig in our Paddock-Blinebry trend, drilling vertical oil wells. So that gets you pretty close to the number. And we are building it -- and your second question was infrastructure takeaway. It's a challenge. One of the reasons that this area in Culberson County is still relatively undeveloped is it has had marketing issues. I mean, there are pipelines going through the area, but all those pipelines are not set up to take rich gas. We're building some pipeline infrastructure. It's certainly a challenge that a number of us are working on. But we're on top of it in getting ahead of our program, in terms of takeaway capacity. Joe, do you want to add to that?

Not really too much more, Tom, other than the fact that we're giving it, being new. I think we're in a good position to proactively look at how we ultimately see this thing looking rather than reacting to the way it was put together when we got out there. So we are looking at three or four different markets for the gas and looking where we can put in our own pipeline infrastructure to give us alternatives to various markets.

We have solutions, David. And if we -- we have several solutions today, but we're just looking for an optimum one. We will be able to move our gas off of these leases.

And your next question comes from the line of Eric Hagen.

Anadarko Basin, just like the Permian, a big acreage position there. We've heard of some new well plays. Mississippian oil for one, developing there. Do you have any exposure to that? Any plans to test that or have you been testing it? And if so, when might we get some results on that?

Yes, Eric. This is Tom. We haven't talked at all on this call about emerging plays. And I want to say we're always -- that's probably one of our primary focuses as a management team, looking at some new things and trying to add to enlarge our map of places we're focusing on. Anadarko Basin is one of the places we're just really, really focused on right now, developing some new ideas. That said, we're not in a Mississippian play. We looked at that sometime back and elected not to get aggressive there. There are some things there we were just unable to understand. And I'll defer you to others that know more about it or speak more about it. If we missed that one, it goes on our list of plays we missed. We have a little bit of acreage up there but nothing critical mass.

And there are no questions at this time.

Thank you all for joining us today. The call went a bit long, but appreciate all the questions and looking forward to continue reporting to you in future quarters. Thank you very much.

This concludes today's conference call. You may now disconnect.