Coterra Energy Inc. (CTRA) Q1 2011 Earnings Report, Transcript and Summary

Good afternoon. My name is Molly, and I will be your conference operator today. At this time, I would like to welcome everyone to the Cimarex First Quarter 2011 Conference Call. [Operator Instructions] I would now like to turn the call over to Mark Burford. You may begin your conference.

Thank you very much, Molly. And thank you, everyone, for joining us today on our first quarter conference call. We did issue our financial and operating results news release this morning, a copy of which can be found on our website. I will point you to the end of this news release which discloses our forward-looking statements disclaimer. And we will be making forward-looking statements on today's call. Here in Denver we have Mick Merelli, Chairman and CEO; Joe Albi, Executive Vice President of Operations; Paul Korus, Senior Vice President and CFO; and Jim Shonsey, Vice President and Controller. Unfortunately today, Tom Jorden is not available. He's traveling today, so he won't be with us covering the details of the call here in Denver. But we'll go ahead. We've got quite a bit of information to cover, so I'll go ahead and jump into the call and turn the call over to Mick Merelli.

Thanks, Mark, and thank all of you all for joining us here today on the call. To add a little bit of color to what Mark has said about Tom, he had his -- he promised, I guess, his family he'd take them someplace on his anniversary. So as far as I know, he's headed back to Denver from someplace like Fiji or something here this weekend. And so we'll have him back working next week. Our net income totaled $118.2 million or $1.37 a share for the quarter. Cash flow from operations for the quarter was $305 million. Our daily production average, 590 million cubic feet equivalent per day this quarter, it was comprised of 328 million cubic feet a day of gas and 43,735 barrels per day of liquids. So that works out 50% -- 56% gas and 44% liquids using a 6:1 conversion. On a revenue basis, 32% of the revenues were from gas, while liquids accounted for 68% of the revenues. Production was up 1% over last year and flat with the fourth quarter. Joe's going to cover our production in more detail, but I want to point out just a couple of things. First of all, you know that we had some weather issues, us and many other companies. We had weather issues in the Permian and the Mid-Continent that hurt our production this quarter. But also influencing some of our production was an increased backlog of uncompleted wells. Joe will be addressing this later, but just what's really happened is we have about 31 wells waiting on completion. That's a little bit bigger backlog than what we're used to seeing. And one of the reasons for that is it's kind of a combination of 2 things. It's a combination in a couple of our project areas, both in Cana and in the Permian, where we have larger project areas. We tend to frac a well and we tweaked the frac, and then we decide did it work or not and what else will we do on the next one. Sometimes it kind of slows us down. But what really slowed us down in addition to that was this year, we tried to -- we recognized that there was a potential for some improvement by using slow flow. The problem with slow flow is that it takes us longer to figure out whether or not the way we treat the fracs are working. So anyway, a combination of those things slowed us down and got us into a backlog. I think they feel pretty good about what they're -- where they're at with their frac jobs now, and they're going to pick up the pace next quarter. In the Gulf Coast, production adds from our drilling program are also delayed in quarter one. We drilled some dry holes and we drilled some producers. And our problem there is we never -- when we drilled and when we start the wells, we never know which way they're going to be. So it worked out that the main well's a dry hole, so it was one of the first wells we drilled. In addition to that, we took our rig, we had a mechanical problem at Jefferson Airplane, so we moved our rig over and sidetracked an existing producing well and took the rig out of our drilling order. I think Joe will be talking a little bit about the fact that we're going to add a couple of rigs and maybe go up to -- well, we will go up to 3 rigs in the Gulf Coast. In terms of our future forecast, we're forecasting solid production growth on both the Permian and Mid-Continent. And of course this will -- we still have Gulf Coast declines that we'll have to overcome. I guess -- I'll try to be a little brief here and turn this over to Joe. But really what we track and what we focus on so much is the drilling program and whether what kind of return we're getting on that program. Our first quarter capital investment was $337 million. It was funded out of our cash flow and cash on hand. That program looks very solid to us in terms of the return and the quality of the wells that we drilled. So with that, I'll turn the call over to Joe, and he can kind of take over for some of the stuff that Tom usually talks about, the production stuff that he normally talks about. Joe?

Thank you, Mick, and again thank you all for joining us today. As Mick mentioned, with Tom out of the pocket, I'll cover not only our operations update, but I'll hit on this year's joint program and capital as well as I go through and integrate the 2 reports we typically give you. Our first quarter production came in as anticipated, with average reported net equivalent production of 590 million a day. We came in just about at the midpoint of our guidance, which was 582 million to 602 million. As expected, our Q1 production was impacted to the tune of 10 million to 15 million a day from our early February weather-related shut-ins as well as about 4 million a day from our late 2010, early 2011 property sales. Despite the weather delays, we saw year-over-year total company production gains with our Q1 '11 production of 590 million a day beating our Q1 '10 production of 584.5 million a day by 4.5 million a day. When comparing Q1 '11 to Q1 '10, a combined year-over-year production gain of 46 million a day from the Permian and Mid-Continent more than offset the sharp 41 million a day drop that we forecasted and actually saw in the Gulf Coast. Approximately 2/3 of our weather-related downtime occurred in the Permian. And despite the downtime, our Permian Q1 '11 average equivalent basis of 174 million a day was up 12% or 20 million a day from our Q1 '10 average of 154 million a day. All the while our Q1 '11 Mid-Continent average of 266 million a day was up 11% or 26 million a day from our Q1 '10 average of 239 million a day. As I just mentioned, the combined 46 million a day year-over-year increases in the Permian and the Mid-Continent, they offset the 41 million decline or 22% drop that we did anticipate and saw in the Gulf Coast, which fell from 190 million a day in Q1 '10 to 149 million a day in Q1 '11. The bottom line to our Q1 production is that despite the weather interruptions, the Permian and Mid-Continent programs continue to exhibit the consistent production growth that we've seen quarter to quarter, and they offset the decline that we saw in the Gulf Coast. This has been a pretty consistent story for us now for about a year and will likely be the same story here in Q2 with our Gulf Coast area net daily equivalent production projected to drop from levels of 149 million a day in Q1 to levels of 100 to 105 million a day in Q2. Our high cash flow and high rate of return Gulf Coast program inherently brings a variable of uncertainty in the timing of production adds and drops. And we've seen these ups and downs in the Gulf Coast over the last few years. But as I'll go into in more detail, the real catalyst for Cimarex's long-term production growth is our multi-year inventory of projects in the Permian and Mid-Continent. We've seen nice production gains in both of these programs, and we expect it to continue. Well, let me jump into our exploration and drilling activity before ending with some additional comments on our production and our guidance. Overall, we drilled and completed 65 gross or 35 net wells during the first quarter, investing $337 million. Of total Q1 capital, 50% was invested in projects located in the Mid-Continent, 46% in the Permian and 4% in the Gulf Coast. I'll briefly touch on each of the regions, and I'll start here first with the Permian. During Q1, we drilled and completed 26 gross or 19.7 net wells in the Permian and at quarter end, 18 net wells were waiting on completion, up from the 10 net wells that we had at year end. While Mick touched on this a little bit earlier, more so in the case in the Permian with our accelerated activity, a tight market for frac equipment and the bad February weather really slowed down our completion activity here near the end of Q1. As we stated in our last call, we were hopeful to see signs of the market loosening up a bit here into Q2, and we certainly have. We firmed up solid plans to add at least 3 additional fleets to the Permian in the May-June timeframe to catch up on our backlog with a minimum of 5 frac crews working in the area by the end of Q2. We contemplating a sixth. Our current frac schedule calls for us to significantly reduce our backlog of wells, waiting on completion here by the end of Q3. Our Permian E&D capital totaled $154 million in Q1. That represents about 46% of our total company Q1 capital. For the full year, we're expecting to invest $700 million to $750 million in the Permian, which will represent about 50% to 55% of our total 2011 capital budget. As I mentioned previously, we continue to see solid production growth in the Permian. Our Q1 '11 production averaged 174 million a day equivalents, which on a BOE basis equates to 28,954 BOE per day, so 12% increase over Q1 '10. And the real driver of that growth has been our New Mexico second and third Bone Spring horizontal oil plays. We continue to see great results from these programs. During Q1, we drilled and completed 8 gross or 4 net wells with another 11 gross or 7.7 net wells waiting on completion. By year end, we expect to drill a total of 60 gross or 39 net wells in the play, investing nearly $200 million. Since we kicked off the play in mid-2009, we've drilled and completed a total of 36 wells. And those 36 wells gave us a first quarter gross exit rate of 6,800 BOE per day, which was up from 0 not quite 2 years ago. Our absolute EURs for the wells that we drilled and completed is 570,000 BOE, and that's comprised of 416,000 barrels of oil and 920 million cubic feet of gas, virtually the same number we've been quoting to you all for months now. With these reserves, the 570,000 Mboe or 570,000 BOE, we're seeing very attractive rates of return. But our economics continue to be squeezed just a bit as compared to last year. Although we've seen some overall cost ability over the last 3 months, drilling and completion costs have moved up from last year primarily as a result of our increased frac costs. Our generic second Bone Spring completed well now runs around $4.8 million to $5.2 million and that's up 20% to 30% from last year. But even with this cost creep, this play continues to be a great play for us. And we have a deep, multi-year inventory of future drilling opportunities. Shifting gears a bit, I have a few comments on our emerging Delaware Basin/Wolfcamp shale play. As we previously mentioned, this is a play which covers a very large potential area from southern Eddy County, New Mexico, down south into Culberson and Reeves Counties in West Texas. As most of you know, most of our activity to date has been focused right in and around the state line. During Q1, we drilled and completed 2 gross or 2 net Wolfcamp shale wells in the area, bringing our total completed, I'll call play concept well count to 8 producers. We have another 5 gross or 5 net wells which are waiting on completion and pipeline connections at quarter end. And we're currently working on infrastructure and markets for these 5 wells and anticipate having them completed and online here by late Q2, early Q3. One of the 2 wells that we drilled during Q1 was located in our White City area in Eddy County, New Mexico, and the other was a reentry further south in Reeves County, Texas. Our results continue to be encouraging, but we're still in the very early stages of evaluating the play. We currently have 3 wells drilling in the play with AFEs to drill and complete running in the $6.5 million to $7 million range. Today we seen no additional information which would have us depart from the average play production statistics we previously provided you. And those were an average equivalent 30-day IP of about 6 million a day composed of 50% gas, 32% natural gas liquids and 18% oil. We a great acreage position in the play. It totals 125,000 net acres. Not only do we see the acreage as perspective in the Wolfcamp, which by itself has significant potential to Cimarex, but we also have exposure to the Avalon Shale and the Cisco/Canyon shales as well. Although our early emphasis has been on the Wolfcamp, we do have wells planned in the Q2, Q3 timeframe to test both the Avalon and the Cisco/Canyon intervals. By year end, we expect to drill a total of 25 to 30 wells in the play, and end the year with a 2011 drilling investment of approximately $200 million in the play. As you all know, the Permian is a hot area right now. Competition is fierce and costs are rising. Our plans are to continue to aggressively move forward, and we'll maintain a strong focus like we always have on rate of return and continue to test our economics with sensitivities using flat price stats to hydrate our portfolios. We have a great land position in the Permian. The basin's an integral part of our ongoing business, as you all know. We have a solid multi-year inventory of future drilling opportunities on our existing acreage. And you'll see us continue to add acreage when and where we can, only as long as it continues to make sense. The Permian team has done a great job of picking up activity and developing the program. We're really excited about its momentum and what the program brings to the table. Moving onto the Mid-Continent, during Q1 we drilled and completed 37 gross or 13.2 net wells in the area. And at quarter end, we had 32 gross or 13 net wells in the process of either being completed or awaiting completion. The majority of wells waiting on completion were in Cana. And similar to our plans in the Permian, we firmed up the addition of another fleet this month to catch up on our backlog of completions. With 2 frac crews working Cana starting here in May, our current frac schedule calls for us to significantly reduce backlog of our completions by the end of Q3. Our Mid-Continent E&D capital in the first quarter totaled $169 million or about 50% of our total company Q1 capital. And for the full year, we expect to invest $500 million to $550 million in the Mid-Continent, representing approximately 40% of our anticipated total company capital spending. As we've mentioned, our first quarter 2011 Mid-Continent production averaged $266 million a day. That's up 11% over our first quarter. And a main driver to this growth is our Cana/Woodford Shale play, which as most of you all know is in the Anadarko Basin. In Cana, we've drilled and completed 31 gross or 9.6 net wells. And at quarter end, we had 29 gross or 11.1 net wells waiting on completion. We currently have 9 and soon to be 10 here in June operated rigs working in Cana and we're drilling one well per section. We still anticipate being a bit over a year away from initiating our down spacing development, but we wanted to continue to evaluate optimal spacing and as a result, we've begun a 2-well pilot to help further evaluate spacing, which we hope here to have completed in the Q2, Q3 timeframe. Outside of that, we'll continue to drill on the core and on the peripheral of the bill to continue to further develop and test the play. Our generic Cana AFEs for the shallow and core areas have stayed somewhat flat over the last 3 months at levels of $7.5 million to $8.5 million, but they are up approximately 10% to 15% from the well cost that we saw in early to mid-2010. We're still leasing and hydrating our land position in Cana and hold a very strong land position with over 135,000 net acres, 70,000 of which we believe are located directly in the core. Cana continues to be a great play for us. We're very proud of it, and it's moving forward very nicely. In other areas of the Mid-Continent outside of Cana, we drilled 5 gross or 2.8 net wells during Q1, with 3 gross or 1.8 net wells located in Hemphill County, Texas, and 2 gross or 1.2 net wells located in Custer County, Oklahoma. Two of our significant Hemphill County Granite Wash successes include our George 17-5H, in which we hold a 61% working interest, which came on during the quarter with a 30-day IP of 8.6 million a day. And our George 17-6H in which we also hold a 61% working interest, and it came on at 8 million a day. Of significant note, Custer County was the successful drilling of our Kephart 1-4, our Hogs bar or Hogshooter test, in which we hold a 91% interest. It came on with a 30-day IP of over 1,000 BOE per day, 71% of which was oil. Moving on to the Gulf Coast, during Q1 we drilled 2 gross or 1.8 net wells, testing the Kirby and the Yegua/Cook Mountain series, one of which was successful. Our first 2011 test, our Two Sisters #3 well in which we own 100%, was successfully completed in early January. And it came on at rates of approximately 9 million a day and 1,600 barrels of oil per day. Our second 2011 Gulf Coast test, as Mick mentioned, our Manion #2 was a dry hole. Our Gulf Coast E&D Capital in Q1 totaled 13 million or about 4% of our total Q1 capital. And for the full year, we expect to invest $100 million in the Gulf Coast program or about 8% of our total company capital. We have a variety of identified remaining 3D prospects, a good mix of larger higher-risk projects and smaller lower-risk projects. Our original 2011 Gulf Coast plan called for us to run with a one-rig program and possibly add a second rig line from time to time during the year. But as Mick alluded to, we're stepping up the pace of our Gulf Coast program by adding a second rig in the next few weeks and a third rig here in June. To the extent the prospects that we have are non-contingent, you'll see us get them drilled as soon as we can. And as such, depending on our success, will either see us end the year with 3 rigs or not. I'll cover some of the other Gulf Coast items as I go over our second quarter and full year production guidance. When discussing second quarter full year '11 guidance, I think it's important to touch on a couple of factors which have implicated our guidance. First is our backlog of Permian and Cana wells waiting on frac. Mick touched on 2 factors really playing a role here, and I'll reiterate them. One was our desire to test and understand various completion techniques, and the other was a tight market for frac equipment. As you may recall, starting in the latter part of 2010, we purposely had a backlog of completions in Cana due simply to our desire to test and understand various completion techniques in order to optimize our completions. Post completion production performance, which is in essence time, is needed to evaluate results. Compounding that time necessary to evaluate are those instances where slow flow techniques are used to flow wells back. Well, 6 months down the road now we're feeling more confident about the completion designs we're utilizing in Cana and in the Permian oil plays and we're ready to speed things up. To do so, we firmed up the addition of at least 4 additional frac fleets to the 3 existing fleets we had working in Q1. With additional fleets scheduled to show up in the May, June timeframe, our current frac schedule calls for us to make a good dent in the backlog by the end of Q3, with forecasted associated production uplift beginning in late Q2 and into Q3. Secondly, as you all are aware, success in our Gulf Coast program can create significant periodic swings on our production, both up and down. As we've said before, predicting the timing and success of these 50% to 60% COS high-rate wells will play a sensitive role in our guidance projections, especially in the case of the single rig program where a well either hits or it doesn't. Third, the need to cut back on our existing Gulf Coast Beaumont area producers to protect them against sand flow has impacted our production as well. In our Jefferson Airplane area, despite cutting back the wells, by the end of the first quarter 3 of our 4 operated wells had ceased production. With this being a competitive reservoir, we made the decision to sidetrack our Jefferson Airplane #2 well with a rig we had working in the 2011 Gulf Coast inventory. We just recently submitted pipe on the Jefferson Airplane #2 sidetrack earlier this week, which frees up the rig to get back to work on our 2011 inventory. Our Gulf Coast program is now delayed, hence us adding 2 rigs to the program: one in May and the other planned for June. And finally, in addition to the 2 rigs we plan to add in the Gulf Coast, we have plans to add additional rigs in the Permian and the Mid-Continent, which should bring our anticipated rig count to 30 rigs in the Q2, Q3 timeframe. So with accelerated activity, both in rigs and completions, we expect continued strong production growth in the Permian and Mid-Continent during the second quarter with anticipated increases of 5% to 10% from reported levels in Q1. With the production cutbacks and delays we've mentioned in the Gulf Coast however, our Gulf Coast volumes are expected to drop 45 million to 50 million a day or 30% to 33% from Q1 to Q2, but it's a drop our Permian and Mid-Continent programs are projected to overcome, and hence our flat guidance of 580 to 600 here for the second quarter. Looking at our full year 2011 guidance, we expect continued strong production growth in the Permian and the Mid-Continent during Q3 and Q4, projecting approximate year-over-year production growth of 15% to 25% in these areas. Our current modeling predicts our 2011 Gulf Coast volumes will exhibit a year-over-year drop of $62 million a day or 35% from an average of $174 million a day in 2010 to $112 million a day here in 2011. However, our strong Permian and Mid-Continent production growth is projected to continue to more than offset that Gulf Coast decline, resulting in our revised guidance of 605 to 635 million a day, a range which equates to 2% to 7% production growth over our 2010 average of 596 million a day. The bottom line to our quarter is this: Nothing's changed in the way we think or what we do. We continue to stay focused on maximizing our return on investment through deliberate evaluation and execution. We have high cash flow, no significant debt, a deep inventory of drilling projects in each one of our core areas. We're seeing Q1 and Q2 production impacted by weather, production cutbacks in the Gulf Coast and delayed production adds in our Gulf Coast program, but we're teed up for production growth in the latter half of this year. We have an accelerated plan to catch up on our backlog of completions, and we've increased drilling activity in each one of our core areas. Most importantly, we have established momentum in our 2 long-term growth programs, the Permian and our Mid-Continent programs, the programs with deep multiyear inventories of drilling. And over time, the depth and consistent growth of these 2 programs will ultimately dominate the growth of our company. So with that, I'll turn it over to Paul.

Thank you, Joe. I just want to cover a couple of things from the release and the numbers that we've gotten some questions about, one of which is our production costs for the quarter, which increased $3.8 million from the fourth quarter of 2010 when they were $54.7 million to $58.5 million in the first quarter. Not a particularly large increase, about 7%. With all the activity in the industry, particularly in the Permian Basin, now services are tighter, costs have increased. That's a portion of it. It's very hard to isolate. But more logically, I think you can see the impact of just where we have more liquids, particularly oil, in our overall production mix. If you think about where we were a year ago, when our gas production was 390 million a day, and that was 67% of our overall production. Now our gas production is 327 million a day, and it represents only 56% of our production. So as we become [Audio Gap] we're dealing with wherever you produce oil, you produce water. Those pumps require power and fuel, so those are additional costs. We incur trucking costs for saltwater disposal, as well as disposal costs. So some of it is really just the invisible hand of the economics allocating our capital more towards oil projects versus gas projects, which are inherently much lower cost. Just anecdotally for instance, if you look just at our Cana production from the Cana wells, our production cost is only $0.13 in Mcfe. Whereas if you look at and dissect our production cost in the Permian Basin, which is 50% oil, our production cost is $1.66 per Mcfe. So you can see how the blending of more Permian base production is leading to the higher cost. Having said all that, our margin in the Permian Basin is by far in excess of our margin in Cana, which is predominantly gas. So the bad news is production costs are up a little bit because we have more Permian activity. The good news is we're making more money because our operating margins are much higher in the Permian than they are anywhere else in the company. The other thing that's gotten some attention is our tax position for the quarter, where we essentially deferred 100% of our booked tax provision for the quarter. That's new. I think everyone's, of course, aware that part of the stimulus legislation that we have -- had passed is what's known as bonus depreciation, which essentially allows the capital cost for equipment to be 100% depreciated in the year in which they were put in service. So it's a large acceleration of depreciation. So essentially our equipment costs are being traded the same way as our intangible drilling costs are this year. So as a result of that and with a larger capital budget overall, we do not anticipate at the present time that we would have a Federal tax liability for the year. And hence, we deferred 100%. Obviously, there are many moving parts in tax calculations, the biggest of which is revenue. So it's -- the prices for gas and oil, as they go up and down, could have an impact on that as we move forward. Lastly, I just want to add, for any of our debt holders on the line, I hope you noticed that we were upgraded by S&P here recently to BB+. With that, operator, we would be happy to begin to entertain questions.

[Operator Instructions] Your first question comes from the line of John Freeman. [Raymond James & Associates] John Freeman - Raymond James & Associates, Inc.: The Oklahoma Legislature recently approved the cost units facing Oklahoma. I'm curious if you have any plans in the Cana to do a 12 80 spaced long lateral well?

Yes, this is Joe Albi, John. In fact, Mark and I were talking about that this morning and expecting this question. We do have plans this year to test the concept in the southern part of Cana. And it probably won't be 12 80, just due to the sections that we'll be trying in. We don't see it as being something that we do in areas of the field that we've already developed on within a 640 with 5,000-foot laterals, but it is something we're also exploring. John Freeman - Raymond James & Associates, Inc.: Okay. And then moving to the Gulf Coast. Just want to make sure that I understand what's going on. Obviously, the declines there have been well documented the past year. But this quarter, despite some of the issues you all had, the mechanical issues at Jefferson and et cetera, your production was actually virtually flat from the fourth quarter after going several quarters with declines. So I'm just trying understand the reason for, I guess, the big acceleration and the decline from first quarter to second quarter?

This again is Joe. It's a combination of a number of things. First off, we had a one-rig line schedule working the Gulf Coast. We had one successful well at the beginning of the year, our Two Sisters #3 well. It was by no means as big as any of the other Kirby wells that we had. So it was not as good a well, and it has a steeper potential decline. We had our Jefferson Airplane wells that were exhibiting sand problems, and not knowing if it was beyond the scope of that competitive reservoir. There's a number of straws being yanked into that thing by 3 of those operators, and we are not the first to be having oil trouble, I might add. But we've taken a kind of prudent, proactive approach on our other South Texas wells just to be sure. We're pitching back our wells as we feel they're entering a certain phase envelope in the reservoir from a fluid standpoint, and you're seeing a little bit of that. We've got -- I've got a list of them here -- 6, 7 wells that we pinched back during the course of January through March that represent about 36 million a day of cutbacks. And what, in essence that is doing is it's differing that production. So if you look at our modeling, you're going to see that our Gulf Coast with the webs that we're throwing on top of it, it's going to drop for about 145 million a day here in Q1 to Q2. And then it's going to hold 100 for about the rest of the year. And so -- so you see a little bit of a cutback and a push out, if you want to look at it that way.

It's pretty simple. You just -- you decrease the rate and you decrease the rate of decline. And so we just -- it produces -- it can produce that over a longer period of time. So it's going to break that decline rate.

And it's really just prudent reservoir management. The Jefferson Airplane deal may have been a fact that you had 7, 8, 9, 10 straws yanking on that thing so hard. That thing lasted about 18 months and it was making over 100 million a day at one time. John Freeman - Raymond James & Associates, Inc.: Yes. I guess I was looking at it from the opposite standpoint. I actually was really impressed with your first quarter Gulf Coast production despite all the issues you just went over. The production did a lot better than I thought, given the declines you'd had in the prior quarters. So I guess I was just trying to figure out why the production held up so well in the first quarter with all of those problems. And like you said, the one Two Sisters #3 you brought online, it's wasn't that big of a well, relatively speaking, than what you all have done in the past. So I guess I was just trying to get more color on the actual quarter why it did so well. I was on the opposite end.

It did well from a rate standpoint, don't get me wrong. And we had the benefit of that well from early January, when it came on. So it's on most of the entire quarter. But it's not as big a reserve well. John Freeman - Raymond James & Associates, Inc.: Okay. And then the last I had, I'll turn it to somebody else. The move to go from one rig in the Gulf Coast to 3 rigs, is that being driven by the prospects that you see or trying to offset some of these big decline issues that you're talking about right now?

This is Jim. The way I'd answer that question would be I think we recognize we were behind. And the fact of the matter is we've either got projects that are either dependent or not dependent on another project. To the extent we have non-dependent projects, the sooner we get them done, the better. And it kind of smoothes out the volatility, if you want to call it that, in trying to project our guidance if you got 2 or 3 rig lines working. So it's simply a matter, in my mind, of accelerating those projects that we know we're going to drill anyway and just get them done this year

And the other thing is, is that every time we drill a dry hole on the data set, we have to relook. Because we saw an anomaly, a seismic anomaly that we thought would produce. And it didn't. So they get a sonic log out of the dry hole and then they have to see what does that mean to that data set and what does it mean to the other prospects that we have out there. So that slows us up a little bit when we see one. We have to look at it and see if we can explain it. What does it mean to the other prospects? So it slowed us up a little bit. They looked at that, they've got a bunch of prospects out there, as Joe pointed out, that are non-contingent, and so we'll get in there and try to get them drilled now. But some of that delay is something and it depends on the reason that, seismically, what happened? What was the reason that the well didn't produce? And they have to take that apart and go through it. So every time we drill a dry hole, it kind of makes us look. John Freeman - Raymond James & Associates, Inc.: Well, that's very helpful.

Your next question comes from the line of Gil Yang with Bank of America.

You talked about the Permian frac availability loosening up a little bit so you could lock in some more frac crews to reduce your backlog. Can you talk about the pricing that you saw on those incremental crews?

Yes, this is Joe again. We virtually are seeing about the same prices across the board. And I think it's just a matter of more equipment being available right now.

Okay. So more equipment, but sort of flat price is what you're seeing?

Flat price. Where our frac costs are going up are when we're increasing stages or fluid or sand. And it has really nothing to do with vendor A being more than vendor B.

All right. Going back to the Gulf Coast to the Two Sisters wells that you put on -- the 9 million, was that sort of a rate that you expected or above or below your expectations?

It's where we felt comfortable producing the well, given how the other wells have performed with regard to sand.

But you didn't have a targeted expectation for that rig?

We targeted right around 10 or 11. So we held it there. And it was holding its own for a while, and we've recently pitched it back, as I mentioned, when it was going through its base.

Another way to answer your question is that that well didn't look like a Jefferson Airplane, Kirby well -- it wasn't a thick Kirby. We weren't expecting one of those kinds of wells out of that well. So it was pretty much like we thought we'd find.

How about the well that was the dry hole? What had you expected? Is that one of the bigger wells that you expected?

We expected that we had a 40% chance of drilling a dry hole, and that's what we got. It probably would have been in the same kind of -- it wasn't. We weren't expecting big thick sands there. Those wells that come in for 9 to 10 million cubic feet a day and make all those of liquids and everything, they're tremendously economic, but they're just not quite as good as those other ones.

Okay. And this is the last question, your CapEx, you say, will be principally funded from cash flow. I sort of got the impression before that you are beginning to think that you would be willing to spend, I won't say a fair amount, but sort of meaningfully above cash flow. Are you beginning to rethink that maybe with the current commodity price volatility that you're seeing?

Paul, you want to answer that? Go ahead.

Well, where our expected cash flow is right now, plus the cash that we carried into the beginning of the year, we still think we can fund something in that 1.4 range. So we're okay.

I think there's one thing that I need to clarify, and that is we like operating out of our cash flow, and it makes the drilling program look a lot better. And I have absolutely no reason -- if we find something we want to accelerate on, if we found some sort of deal out there that we liked, anything, we have such low leverage that that's really not any kind of a problem to us. And sometimes when I hear the question asked, I think that some people believe that we have some sort of rule around here that we're not going to expend our cash flow. And that's definitely not true. So it will depend on what we can get done. Now, frankly, it's booming along at about a $1.4 billion rate. We've got the organization stretched out pretty good. But if we find something that we really like, we'll extend that cash flow if we like the returns.

Your next question comes from the line of Eric Hagen. [Lazard Capital Market]

A question on the Cana. There's been some good results out of the northwest portion of the play. Just to refresh our memory, how much acreage do you have there? And any plans to start drilling more out there?

Yes, Eric, this is Mark. Our acreage is -- we probably only have -- it's a small portion, about 135,000 total acres in that play, probably only 10 or so, it's totally off the cuff here, that's in that Northwest section. We have more of our extensional area. We have more in the south than we do the northwest.

Yes, we have -- we were involved in an acreage buy up there, but the term of that acreage is kind of going out. And so I don't know what we have up there, but we're probably not going to get to it because I think a lot of it goes out in 2011. And so that northwest extension of the Cana project, as far as Cimarex is concerned, probably has its limitations.

Okay. Just back to the Gulf Coast really briefly. How many additional wells do you think you can get drilled with the additional 2 rigs there this year?

This is Mark again. With that couple additional rigs, actually, we're already planning to have one rig and maybe 2 during the year for our original plan. They were scoped down with some of the sidetracking of the Jefferson Airplane well. That third rig actually keeps us on track for our original plan. So probably 10 to 12 wells this year, which we had not originally planned to do.

The other thing, Eric, is that it'll be -- some of the -- a couple of these prospects could have development wells on them. So we don't know. We're just looking at them. But there's funny-looking thing that might accommodate 2 wells. So if we get into some of that, which we hope we do, then we'll get a little bit more done. But we don't know that until we get them drilled. So we're going to blast through the non-contingent part of the exploration program in the Gulf Coast, see what we got and go from there.

Okay, great. And the last one I had is just on the additional rigs being added to the Permian and Mid-Continent. I was wondering if you could maybe break down one of those -- which plays those rigs might be going into. Is it an increase in rigs in the Bone Spring in the Permian, for example, or more Wolfcamp? And in the Mid-Continent, any additional rigs in the Granite Wash or over the Hogshooter?

This is Joe. You'll see us in the Permian. This is just higher level. Probably we'll be back up in the Paddock area. We're going to dedicate some rig activity to the Wolfcamp shale obviously in the Culberson area in Reeves County, as well as in the Culberson County. And then the third Bone Spring in Warwick in West Texas. So those are really the bigger areas. We do have some rigs that we're slating for saltwater disposal projects, to kind of follow-up on what Paul was talking about. Our saltwater disposal cost represented about $0.10 per Mcfe. And we've now got enough production out there we can justify the drilling if necessary and dedicate some rig activity there, too.

Okay. And then in the Mid-Continent, is it additional rigs in Cana? Or will you be accelerating now in maybe the Hemphill County or...

We're going to add one more rig to Cana and probably an additional rig in the Texas Panhandle. And we'll probably throw a rig at Southern Oklahoma.

Okay, great.

[Operator Instructions] Your next question comes from the line of Brian Lively with Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Just thinking about the Hogshooter. Do you have -- what is the acreage position that you have specifically over the Hogshooter?

This is Mark. We talked a little bit about what the team sees as net acres in that area. It's a pretty small amount, but they think they have something like maybe 4,000 net acres or something. But it looks very encouraging as far as economics. That first well was a good well, but as far as extension of running room, it's not that great for us. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. And then -- you guys have been very gracious on the thoughts on the Gulf Coast and I think I got a little confused. What is the current rate of the Gulf Coast?

Today, we're running around 100 million a day. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: About 100 million a day. So that fed into your comments on restricting the rates on the wells and getting that 50%, 60% annual decline to smooth out a bit, and so that's why you came down and you kind of flatlined it through the rest of the year. Is that a way to think about it?

That's our hope, that's our current model. Of note, you'll notice that our full year guidance -- I think this is important -- a little statistic to throw out there. Our full year guidance dropped 10 million a day, midpoint to midpoint. Our Gulf Coast projection is 20 million a day below where we thought it would be when we first put out our guidance. So the Permian and the Mid-Continent have made up an additional 10 above and beyond what we had forecasted at the beginning of the year.

And it's because we can't forecast it's sanding up and a lot of those other things that happened. We've got a lot of -- those are great wells and we love them, but they're hard to predict. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: And given the competitive drainage situation, why can't you and the other guys that are producing do some type of unitization to not damage the reservoir? Or how does that work?

Because we're competitors. And we like it that way.

Mick's answer was we're competitors. And the fact of the matter is that would be very difficult to build it. It started off as a war and it kind of ended as a war, but the irony is the last guy standing will probably be the winner. And a lot of us...

Yes. Your suggestion is absolutely on point. But in practicality, in that part of the world, it doesn't happen. People just line up and compete. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: So the rate at which you produce this reservoir, given the condensate yields, if you pull too hard it won't lower the overall recovery factor?

Not significantly. The thing that you can tell about what we're saying that we're concerned about and we have little devices that listen for sand grains, the problem is, is that sometime we get instead of one sand grain, we get a couple of yards of sand. But that's the problem. At sometime, and for whatever reasons, a lot of people have seen in that part of the world when that pressure comes down and you're at high rates, you can start moving that sand.

And there are no further questions at this time.

Well, thank you, everyone, for joining us today on the conference call. We'll look forward to reporting back to you again another quarter. Thank you.