Coterra Energy Inc. (CTRA) Q4 2011 Earnings Report, Transcript and Summary

Good afternoon, my name is David, and I will be your conference operator today. At this time, I would like to welcome everyone to the Fourth Quarter 2011 Earnings and Operations Results Conference Call. [Operator Instructions] Thank you. Mr. Mark Burford, you may begin your conference.

Thank you, David, and thank you, everyone, for joining us today for our fourth quarter 2011 results conference call. We have issued our financial and operating results news release, and it's been posted to our website this morning. We also posted in our website a presentation that we will refer to from time to time during today's call. And I will also point out that we will be making forward-looking statements on this call, and I refer you to the end of our press release and our presentation regarding our statement regarding forward-looking statements. On today's call here in Denver, we have Tom Jorden, President and CEO; Joe Albi, EVP and COO; and Paul Korus, Senior Vice President and CFO. Paul will make some opening remarks around our financials, and then we'll turn the call over to Tom and Joe to go over the operations.

Great stuff. Our earnings release detailed very positive results of operations for 2011 and a favorable outlook for 2012. Before turning the call over to Tom and Joe to describe these accomplishments and expectations, I'd like to briefly reiterate just a few financial highlights. First off, I need to mention ahead of our review of 2011 is challenged by the fact that it's often compared to our record results in 2010, a year in which we hit on all cylinders and set new highs for most measures. Not even Jeremy Lin scores more points each and every night. Still at 2011, we achieved even greater revenues in cash flow than we did in 2010. Our revenues reached nearly $1.8 billion versus $1.6 billion in 2010. Our cash flow from operating activities rose to $1.3 billion compared to $1.2 billion a year earlier. Our earnings were also strong. Once again, we exceeded the $500 million mark. In 2011, net income totaled $530 million or $6.15 per share. That compares to $575 million or $6.70 per share in 2010, a year in which we had substantially larger hedging gains and non-recurring income from the early extinguishment of some debt. As this usually indicates, the prices we received for our production of oil, gas and natural gas liquids had the greatest impact of anything on our financial results. In 2011, price realizations for oil and natural gas liquids increased by more than 20%. On the other hand, gas prices were 10% lower. During the year, our production and revenue mix changed as we came more tilted towards liquids output versus natural gas. In 2011, about 50% of our production was gas, with 44% being oil and natural gas liquids. Combining with the effect of prices, however, roughly 70% of our revenues were derived from oil and natural gas liquids, with less than 30% coming from gas. The shift in our production mix is no accident. It reflects the choices we make for capital investment. So even though we may not always deliver as robust overall growth rates as some would like to see, we continue to make good profits and are able to do so without levering up our balance sheet or issuing equity. We had good growth in our proved reserves during 2011 and have an equally active capital program plan for 2012. With quality cash flow at a very strong balance sheet, we have a lot of flexibility for how we fund our 2012 program. With that, I'd like to turn the call over to Tom.

Thank you, Paul. I'm going to be working off the presentation that's posted on our website. So if any of you have it up, I'll be starting with Slide 7. If you don't have it up, it's not really that important, but there are some figures in there that might help as I talk. In 2011, we invested a hair under $1.6 billion in exploration and development. We drilled 174 net wells, and as Paul said in this other release, we had extremely solid returns in our Permian and Cana programs. We grew our proved reserves to 2.05 Tcf equivalent, which is a record for us. Our Permian Mid-Continent reserves proved increased 26%, an all-time high of 2 Tcf equivalent. We added 587 Bcf equivalent from extensions and discoveries, and 45% of those adds were liquids, 55% gas. All in all, we replaced 272% of production. But the real story, and we'll get onto that as we give you a little detail, is our record 2011 Permian Basin and Mid-Continent production of 487 million cubic feet equivalent per day. Those 2 regions in aggregate showed a 16% production growth over 2010. Those are our engines of growth. On Slide 8, it shows our core operating areas, now many of you are familiar with this but just to recap, of that 2.05 Tcf equivalent, 98% are Mid-Continent and Permian reserves, and fully 89% of our production are Mid-Continent and Permian. So those are the engines. On Slide 9, it shows us graphically. Slide 9 shows our proved reserves as they've increased the last few years. We have a very solid reserve base. As Paul said, our investments have pulled us towards liquids-rich areas. That's in part tactical, a little strategic, but it's mostly driven by the invisible hand of the disconnect between gas and oil prices, and we are just in a very nice position with one of the best Permian assets amongst our peers, and we can emphasize that oil production by simply shifting our weight. As you can see in 2011, we ended the year 41% liquids; 59% gas, that's a nice healthy growth; compound annual growth rate of 54% of liquids growth, and we ended the year with 82% proved developed reserves, 18% proved undeveloped. The next slide, Slide 10, shows our proved reserves by region, and this again shows the solid growth that we're seeing out of the Permian and Mid-Continent. We've been growing the last few years, a compound annual growth rate of 28%. In 2010, we did sell our Riley Ridge asset in Sublette County, Wyoming. That was 210 Bcf of proved undeveloped gas reserves. That's the gray bar there on your slide on 10. We replaced those reserves, and accounting for that still increased our proved reserves 9%. If net of that sale, if we get back that sale out, we increased our proved reserves 23%. So a very solid year on a reserve basis. Moving on to Slide 11, and now, we'll talk about 2012, which is really the story for us today. 2012, we're going to -- we're giving you a capital range and that's because that we're in a rapidly changing environment. We have a lot of flexibility for 2012, we have a tremendous opportunity set, but we're going to say here this morning what we said for years. We are going to adapt and change to a very changing environment. So one of the things you'll hear us talk about are plans with Cana and plans with the Permian, and those are fungible. Right now, as everybody in the industry, we're watching gas prices carefully, we're watching liquids prices carefully. Depending on local conditions, we may switch some capital from Cana to the Permian or not. I mean, right now, we're seeing outstanding returns in the Permian, and our Permian group is hungry for more capital. Our reserve and production adds from 2012 drilling are expected to be 40% to 50% liquids. In the Permian Basin in 2012, we're currently at 11 rigs and we're planning on averaging somewhere between 11, peaking out at 15 to 16 rigs. In the Bone Spring, we'll get over 60 wells drilled. And our unconventional plays of the Wolfcamp and the Avalon, we have plans for 30 wells. And on our Paddock play, vertical wells, we have plans for 50 wells. So very, very active Permian program, and I'll give you a little more detail that here in a minute. Our Mid-Continent program is expected to average between 10 and 12 rigs for the year, and that would be split between our Cana-Woodford, where we're infilling the core, and we'll drill approximately 110 gross wells there. And outside Cana, we'll have about 20 wells in the Mid-Continent. So very, very active program. As we sit today looking at the landscape, our program is generating very nice returns. As we talked about in the past, we stress test our investments. We're still at a point where we think looking out at today's landscape, we'll be at that $1.4 billion to $1.6 billion of 2012 investment. Moving on to Slide 12, this is just a little pie chart of that investment spectrum that compares 2011 with 2012. It shows that this year, we'll be approximately 94% of our total exploration development capital in the Mid-Continent and the Permian. And again, the Permian at 52% is showing $775 million of capital. I will say that our Permian region is, as I said a minute ago, is prepared to invest more if we choose to ask them to. Very nice returns. Moving on to Slide 13, and this is really the story for Cimarex here today and it's one I really want to bring attention to. Last couple of years, and I think a lot of people in the industry have looked at our Gulf Coast headwind and our production, and we're happy to say this morning that we feel that issue is fully behind us, that the underlying growth of the Permian Basin and the Mid-Continent assets has stepped up the plate and are really showing themselves the engines of growth that we've all known they would be. Over the last couple of years, we've increased our Permian Basin and Mid-Continent production at a compound annual growth rate of 19%. Our guidance this year, and Joe will give you detail, is between 4% and 10%. We have fully overcome that Gulf Coast headwind and we really look for significant growth, or the opportunity for significant growth, for many years to come. I use the word opportunity deliberately because we haven't changed our DNA. We are still about returns, and we believe that production growth is a very nice consequence of making good investment returns. That underlying Mid-Continent and Gulf Coast -- or excuse me, Mid-Continent and Permian program is generating very nice returns, and it's just affably making this Gulf Coast issue not worth talking about. We still will have a Gulf Coast program this year, but none of that is built into our guidance. And it -- and we're at the point where we're growing this program where it's no longer the relevant issue it's been in the past couple of years. Slide 14 is really a nice evidence of the Permian oil production and what it's done in the last couple of years through our very active horizontal drilling. Compound annual growth rate last couple of years of 24%, and year-over-year 2011, 2012, we're expecting 26% to 32% growth in our Permian liquids. So moving on to Slide 15, I just want to give you a little bit of color in our Permian program. You can read that slide to yourself, but the -- really, summary is that we're expecting to invest, I would say $775 million to $800 million of capital in the Permian Basin. We will drill 150 gross wells and that's multiple projects. We're in the Delaware Basin with multiple projects, so just as we value diversity throughout our overall investment portfolio, we have a fair degree of diversity in our Permian. And I'd like to give you a little color on that. Moving on to Slide 16, I want to talk for a minute about our Bone Spring/Avalon play. Our second Bone Spring play of Eddy and Lea County, I just kind of want to brag on our team for a minute. In our third quarter call, we talked quite a bit about the wrestling match we had internally with some of our technical challenges. And I want to just compliment our exploration group, our operating group for getting after it, figuring that issue out, and they came back roaring with an absolutely outstanding fourth quarter. And that we are a geoscience-driven outfit that focuses on being good at the business. And we like to talk about results and not hype. And certainly, our third quarter call, we were in the middle of a wrestling match on our own results. And today, we're happy to tell you that it really does look very, very nice as a result of the great work our teams did. We have some highlighted wells in our second and third Bone Spring play. We're not talking about particular well results, but I will tell you that we brought on several wells on the equivalent basis that are well over 1,000 barrels a day, the first 30-day average. Our release has our absolute program, 30-day IPs of 597 barrels of oil per day. And as we said, there are some really nice wells in that mix. It's generating outstanding returns, and we have a very, very nice inventory of opportunities there. We've also had some just absolutely lights-out returns in our third Bone Spring play in Texas. That's a play that, of course, a lot of our competitors are drilling, and that's gotten a lot of attention, and rightly so. We have drilled a number of wells that have averaged well over 1,000 barrels a day for their first 30-day average. I know that some of our competitors have released some results in that play, and we would just say to you that we see it as they do and that is an outstanding play. We will have in that play, as we look at 2012, we'll have 3 rigs running and currently going to 4 rigs in that play, and that should be a very active investment for us for years to come. Moving on to Slide 17, just to kind of summarize that, if you look at our Bone Spring and Avalon play, we have significant future drilling. We're having very solid returns in that play, and the issues we discussed on our third quarter call, I will say, our actual to expected results are outstanding in the fourth quarter and moving into this year. That team has really dialed that in. We compete for our opportunity, that's why this issue is important to us. Although even at our -- the third quarter, our results were good, when we're going and competing for opportunity, good isn't good enough for us. We need to be able to predict our results and deliver what we predict. And they've really made some great, great strides in the fourth quarter. We're seeing that play, the second and third Bone Spring play in Eddy and Lea County between 400,000 and 600,000 barrels of oil equivalent per well. This year, we're currently at 5 rigs in the second Bone Spring play. We'll go to 7 rigs at the end of chicken season here by late spring. As I said in our third Bone Spring play in Texas, we're currently at 3 rigs, we'll go to 4 and then we'll have 1 or 2 rigs running in the Avalon. But let's move on. I'd like to talk about our Wolfcamp play. We've had some nice recent results in our Wolfcamp play. I am on Slide 18 for those of you that pulled our slide presentation down. We've had a really nice fourth quarter in the Wolfcamp play. We talked last year about some of our development being deferred because of the infrastructure. The slide there shows the trunk line, gathering line we had to build. We had to build roads, bridges, saltwater disposal. We had to put in a little processing facility. Our operations group did an outstanding job getting that online, it's just about complete now, and that allowed us to come in and complete some wells. As the results indicated on the slide there, in the fourth quarter of 2011, we completed 4 gross or 3.4 net wells. And of those wells, our first 30-day average, and this is an average, was 6.8 million cubic feet equivalent per day. And that's 38% gas, 31% natural gas liquids and 31% oil. So we're seeing that play, well over 50% liquids, just generating some outstanding results, our recent wells. As you can see from this map, we're still kind of sparsely sampling this area. So one of the things I would discourage anyone from doing is taking those fourth quarter results, dividing it by some acreage spacing and papering that area with it. But we're drilling our way to understand that. We are extremely encouraged with our recent results. I know there's been some press given to this Wolfcamp play in the Midland Basin. A lot of the people in the Midland Basin are really talking about the Wolfcamp being an outstanding play. I would just say we love this play based on our recent results. We see it as a significant part of our future going forward in 2012 and beyond, and we have an outstanding inventory. If you look at that 80,000-acre position, you have -- we don't know what the spacing is, but if it goes to 160-acre spacing, we've got 400 locations. If it goes to 80-acre spacing, we have over 800 locations. These wells are $8 million a copy. So this play alone is many, many years of drilling inventory at our current Permian Basin run rate. So again, it's a testament to our exploration operations group that built this play from scratch and we're very, very pleased with the results we have to report to you. I'd like to move on now -- before we go to the Mid-Continent region, I also want to tell you that we have drilled now a couple of Avalon wells in the oil window. We had talked about that play in the past. We're still in the process of evaluating that play. We know some of our peers are very excited about that play, and I will say that based on our recent wells, we're starting to share that excitement. We don't have yet 30 days of production on any one well. We have one well that's a few weeks of production, another well that's got a week of production. But I will share with you that our initial results are right in line with what the industry is seeing. That is a high-decline play, so those wells can and do come on in excess of 1,000 barrels equivalent per day. They do decline rapidly, but they do generate very nice returns at current costs. So we'll have the Avalon being a significant portion of our 2012 program. We'll have one rig running in the Avalon here through much of the year, and we're actually in pretty serious discussions about an 80-acre down-spacing project within the Avalon. I'd like to move on, in the interest of time, to our Mid-Continent program, and again, I'm on Slide 19. Our Mid-Continent program, of course, is many different programs. We always talk about the Cana play, but I want to just say, again, we get asked a lot about new ventures. And one of our most active area of new ventures is in the Mid-Continent. We've added a lot of geological horsepower in the last year or 2, and we are working on some new concepts in the Anadarko Basin, which is a very multi-pay, rich basin. And I fully hope and expect in subsequent calls to be talking to you about new horizontal plays in our backyard in the Anadarko Basin. And moving on to Slide 20, this is a little blowup of our Cana play. This is the area where we have 120,000 net acres. We've been transitioning into 2012. In 2011, we were testing the Cana D play. And that's the area, for those of you that are looking at the Slide 20, that's the area off to the West at about that 16,000-foot depth contour. And we had very good results, but not sufficient to really make a living at today's pricing. So we've moved back into the core and we're embarking on an infill project in the core, I'll give you a little more color there. But I think you would expect, as you look at 2012 for our Cana program to develop much greater capital efficiency. The returns in the core are very good even at today's market, and we've moved our activity for 2012 into the core. Slide 21 gives you a little bit of detail. On Slide 21, there is a stippled white row of sections there in the upper half of that slide. That's the area of the core in which we are currently infilling. We're going to 9 wells per section. We have 10 rigs currently running in that infill project and drilling 9 wells or the nominal spacing that people talked about there, a 64-acre spacing. That will be a significant contributor to our production this year, although as I'm sure Joe will talk about, because of the logistics of drilling all those wells side by side, there'll be some delay between when we drill and when we complete those wells. We're drilling those wells from pads. There's 2 wells per pad. They're costing us approximately $8 million per well, and we expect to deliver 6.5 to 8.5 Bcf equivalent per well ultimate production. So it's quite a project. There are a lot of infrastructure involved, a lot of planning, a lot of construction, but it really does look like a project that's potentially going to deliver outstanding returns to us even at today's market. So in summary, for the Cana-Woodford play, I'm on Slide 22, for fourth quarter 2011, our production there was 158 million cubic feet equivalent a day, which was a 59% increase over Q4 2010. We have significant unbooked potential on that core. We have over 730 net locations, 2,200 gross wells, a 4.5 Tcf equivalent of net resource potential. And as we represented in the past, we have $5 billion to $6 billion in future drilling capital and a large resource potential outside of our core. And we still are doing some science in that deep and hopefully, we can make that work. I want to end on the Gulf Coast. I'll use a poor analogy. The last 2009, 2010 were kind of binged exploration years in the Gulf Coast, and maybe you call 2011 a hangover year with that binge. We have that fully behind us now. We're still active in the Gulf Coast. We are in the process of acquiring, processing and evaluating at least 3, and possibly 4, 3D surveys. The one thing that we are committed to do is a little bit of planning in that program. We will very much endeavor to get that activity at a level that will space out and not give huge bowl of the swings on our production. But nonetheless, today's story is when you look at our underlying engines of Permian and Mid-Continent, that issue's behind us. I think you can look at Cimarex for what we are, a diversified company, great resource driller, healthy balance sheet and tremendous potential for returns that will, as a consequence, generate growth. With that, I'd like to turn the call over to Joe Albi, our Executive Vice President and Chief Operating Officer.

Thank you, Tom, and thank you, all, for joining our call today. I'll summarize our Q4 and 2011 production, hit on our first quarter and full year 2012 production guidance, and then I'll follow-up with a few comments on our 2012 exploitation program and where we see service costs. Starting first, I'm not certain of the number of the slides, but this is our Q4 and 2011 full year projection slide. We had a solid fourth quarter driven by Permian and the Mid-Continent. We reported average net daily equivalent production of 601.4 million a day. That was up 9.4 million a day from Q3, and it beat the midpoint of our guidance by approximately 1 million a day. We spent a lot of time talking about the Permian and the Mid-Continent, and once again, our production statistics reflect that. We set multiple new records in each one of the regions. Our Permian oil production of 19,123 barrels a day, it's a record. It's up 9% from Q3 and 24% from Q4 '10. Our Permian total liquids production of 22,889 barrels a day also set a record, up 7% from Q3 and 25% from last year. Our Mid-Continent gas production of 219 million a day set a record. We're up 4% from Q3 and 12% from Q4 '10. As did our Mid-Continent total liquids of 16,252 barrels a day, which was up 4% from Q3 and 24% from a year ago. The driver in the Mid-Continent here was Cana, where record fourth quarter equivalent production of 158 million a day was up 13% from the third quarter and a strong 59% from Q4 '10. So as a result, we set record marks for our equivalent production, both the Permian and the Mid-Continent, with our Mid-Continent equivalent production of 309 million a day, up 17% from a year ago, and our Permian equivalent production of 215 million a day, up 18% from a year ago. So combined, the fourth quarter Permian and Mid-Continent production level of 531 million a day was up 17% over the last 12 months. So we close the books with our 2011 production coming in at 592 million a day. That's right at the midpoint we provided last call and virtually flat to 2010 after accounting for property sales. But as we mentioned last call, on the surface, we may be flat to 2010, but underneath the hood, our Permian and Mid-Continent production grew at 16% and offset the 70 million a day year-over-year drop that we saw on the Gulf Coast. Hitting on production, Q4 production by region, you can see that our Permian and Mid-Continent production has now grown to the point where the 2 regions make up the lion's share of our production, quite evident when looking at the geographic split of our Q4 production. Combined, the Permian and Mid-Continent now make up 88% of our total liquids and 89% of our gas. On an equivalent basis, the regions now represent 88% of our total company production, with the Permian accounting for 70% of our oil and 51% of our liquids, and the Mid-Continent accounting for 65% of our gas and 37% of our liquids. Looking forward into 2012 with our guidance, as Tom mentioned, we truly see 2012 to be the year that we get the headwind of our Gulf Coast production declines behind us. Our current guidance model calls for continued strong production growth in the Permian and the Mid-Continent, with little or no new well contribution from the Gulf Coast in our models. As a result, we project the Permian and the Mid-Continent to grow at a combined rate of 19% to 25%, with the Gulf Coast projected to just make up less than 6% of our 2012 production. With our emphasis on the Permian and the Mid-Continent, we anticipate continued liquids growth from the 2 regions, with combined oil volumes anticipated to grow at 20% to 27% and combined NGL volumes forecasted to grow at 37% to 44%. And as a result, as we've mentioned earlier in the call, we project our 2012 total company liquid percentage to come in at 46%. 2012, that's a 2-point increase over our 2011 level of 44%. Timing-wise, as Tom mentioned, with production from our Cana infill project expected to come on in late Q2, we're forecasting modest production growth during Q1 and Q2, with accelerated growth projected in the last half of the year. As such, our Q1 guidance fell at the level of -- fell in at the level of 595 million to 615 million a day, and our full year projection came in at 615 million to 650 million a day. I might mention, it's part of that infill project to lever it a little bit. We're drilling these wells in the Cana infill area and we're waiting to frac them until we have a number of them drilled for a variety of reasons. And to give you an idea of what would be waiting on completion as the result of that infill project, we're anticipating that there'd be 15 wells during the May to July time period that are on our frac schedule that are associated with that program. So normally, they would've been completed in a much more accelerated manner, and as a result of our planned scheduling, they'll transpire later in Q2 as far as the completions are concerned. Shifting gears to our production group focus and the operations group in general, the group put forth another solid year for us in 2011, with a strong focus on the base properties. We did a great job optimizing production and maximizing net operating income, all the while putting $65 million of net exploitation capital to work, performing over 375 projects. The majority of our exploitation capital went towards recompletion activity in the Permian and the Mid-Continent, numerous saltwater disposal projects, primarily in the Permian, and infill or replacement well drilling activity in the Permian and in South Texas. The remainder of the capital was directed to a variety of workover, lift and facility projects throughout our operating and nonoperating areas. And overall, the group just did a nice job of optimizing production and net operating income during the year, all the while putting our exploitation capital to work wisely. For 2012, our production operations team will remain focused really on 4 simple objectives: Maximizing our net operating income with an emphasis on LOE reduction through saltwater disposal; ensuring takeaway capacity in our core plays by constructing infrastructure as needed, Tom elaborated a little bit on what we've already done in the Permian there; thirdly, effectively deploying our exploitation capital; and then as we strive for each and every year, maintaining our focus to improve our operating capabilities in the field. With our year-end planning process, our production operations group put together another solid inventory of exploitation projects for 2012. We've identified over 400 projects with more than $80 million of associated capital. The inventory was cold and high-graded, resulting in our targeted 2012 capitalized budget of $60 million to $75 million with more than 300 associated projects. Our 2012 focus in the Permian is simply SWD, with the remainder of our workover recompletion, lift and infill drilling activity staying fairly consistent with what we've done over the past years. Looking at our OpEx, with Q4 lifting costs coming in at $1.18 an Mcfe, we finished the year with an average lifting cost of $1.14. That's about at the midpoint of our 2011 guidance, which was $1.02 or $1.22. As compared to 2010, we saw a considerable cost pressure in virtually all cost components on the LOE side during 2011, but especially the aggregate cost to dispose of produced load water from our new wells. With our focus on SWD projects in 2012, our 2012 lifting cost guidance range of $1.05 to $1.25 is simply just built around the midpoint -- a midpoint equating to our average lifting cost over the last 3 quarters. On the service cost side, completion costs continue to play a vital role in our total well cost. Completion costs now make up approximately 50% of our total well cost for our horizontal well. As we've mentioned before, we've seen frac cost go up significantly over the last year. That's a result of both the design changes and service cost increases, especially in the Permian. As compared to 2010, our total company average frac cost was up 20% in 2011, with Cana up an average of 8% and the Permian up over 40%. That said, we are seeing relief in service cost, particularly in the Permian, and we'll continue to alter our frac designs where we can to help control these costs. On the drilling side, with continuing efficiencies and with market costs appearing to be somewhat flat over the last quarter, we've done a good job of funding the completion cost increases that we've seen to keep our total well costs somewhat in check. With good focus on program efficiencies, especially in our infill program, our Cana core wells are still running about $8 million. That's basically flat to the levels we saw a year ago. Our Permian Paddock and Blinebry vertical AFEs, they've crept up a smidge. They're running right now about $2.2 million to $2.4 million. That's up 15% to 25% from Q1 '11, and primarily the result of increased frac and facility costs as compared to last year. With the drilling of slightly deeper wells and changes on our frac design in our New Mexico section, the third Bone Spring program, those wells are running around $5.8 million to $6.3 million. That's up from levels of $4.8 million to $5.2 million that we saw at early 2011. We've made great strides in our West Texas third Bone Spring wells with stimulation design changes. We've trimmed those AFEs to levels of $7.5 million to $8.5 million. That's down considerably from the $8.8 million to $9.2 million levels that we saw in early 2011. And as we continue to develop and refine our Wolfcamp shale play, especially on the completion design side, our current AFEs are running around $8 million to $8.5 million. That's up from the $6.5 million to $7.5 million that we quoted last year. So as we move forward, our operations and exploration groups are obviously going to continue to work together to improve the efficiencies, take it to the next level, work on drilling design and completion design where we can, and ultimately, just like to keep these well costs in check. In all, with the momentum of a great quarter behind us, we're really looking forward on this and to making 2012 really our year for the Permian and the Mid-Continent. So with that, operator, I think we'd like to turn the call over to any questions.

[Operator Instructions] Your first question comes from the line of Brian Lively with Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: The -- in the past year -- excuse me, your decision to spend relative to your cash flow levels -- sorry, you really haven't had a policy of not outspending cash flows, but if I look at 2012, it appears that you guys are kind of pulling a little bit harder on the outspend. And I'm just wondering, you certainly have the liquidity to fund that. But just what gives you guys confidence, as you look forward, in terms of why to outspend? Is it confidence in your inventory? Is it just cheap cost of debt, desire to bring forward the inventory? If you could provide some more color on that, that would be helpful.

Hi, Brian, Tom is pointing to me to answer your question. At 2011, we had the opportunity to sell some assets that didn't have a long-term future for us. So we were able to fund the 2011 program with cash flow and property sales. We came into the year with, also with $100 million of cash. And as we move into 2012, we look at our opportunity set as providing very good returns in the price environment in which we find ourselves, as constructed as well. I mean we could clearly spend much more on gas-oriented projects if all we wanted to do is grow our volumes faster. But we remain very conscious about returns. So our returns are good. If we feel very comfortable continuing with the level of activity into 2012 that we finished 2011 with, we don't know what cash flow is going to be. We all have price forecasts. None of us are likely to be right. So we'll see what happens as the year unfolds. With the current sentiment -- well, at current prices and current negative sentiment on gas, if we use forward curve or your price forecast or anyone else's, we would come up short of our planned capital program. But we have -- this is why you have big credit facilities in place. And it's why you want to always maintain access to capital markets, in our case, particular, maybe debt capital markets. So we're very confident with what we're doing. Our policy has never really been to stay within cash flow. That has been our history, but not necessarily our policy. Our policy has been to fund good ideas that we could execute on effectively and efficiently, and that's essentially what our 2012 program is.

Brian, this is Tom. I do want to touch on that, and that's a great question. I will tell you that we debate that every day around here, what should our proper level of activity been -- be and have been. We -- as we look into 2012, it's really obviously all about Permian and Cana. And those are 2 different issues. Cana, we embarked on this infill project last fall and we had at regular roll. We moved 10 rigs in, in a line, and we had some decisions to make. When we first started, we said, well, let's commit to absolutely infill 3 sections, and we had 7 lined up, ready to go. And one of the nice things about our program is we have some flexibility. Of our rigs, we only have a few that are under any term contract and they all go away this year. So we would have and do have the flexibility to ramp that program down and kind of decelerate slowly. So we're still -- the guidance range of $1.4 billion to $1.6 billion, some of that involves, hey, what if we slowed down a little at Cana, and we're debating that. Right now, looking at the markets -- and we run those sensitivities aggressively. We've run sensitivities at a horrible gas price, ethane rejection, I mean you name it, we run it. We think that program generates really nice returns today, and that's a testament to Cana. And then the other issue is the Permian. The Permian is just lights out. There's no question that that is generating outstanding returns at today's cost and today's pricing environment. We have the opportunity and we like activity. We are a high-volume outfit. We always have been. And one of the reasons we like activity is guess what? When we're active, we generate more opportunity. We have an active year, we look up and we have more years of inventory than we did when we started because our generating teams, through their own activity, find more things to do. So we have kind of given Cana the mandate of you know what, we're going to go forward and kind of steady as she goes, and we have some flexibility there. Permian, we said, get her done. Those returns are great. As Paul said, that's why that balance sheet is there, and we're very, very pleased with the returns we have going into 2012. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Well Tom, I tell you, I'm a fan of activity as well. It seems like over the last -- since last quarter, that is, the confidence in the Permian has really improved. I mean you talked a lot about it in the call. But it seems like the readthrough on that is that you're just more comfortable with the overall inventory and portfolio in the Permian. And so, I know you just gave 2012 out, but does that reflect then that your view is you have the inventory now in place to really have that high sustainable liquids growth over a longer duration, more so than just the 2012?

Well, I think that's absolutely true. Now we don't like to issue 5-year plans. We've never seen any that's ever worth the paper they're printed on. And of course, prices, costs, I mean, I'm giving you all the standard disclaimers here, but we have multiple years of inventory. Our second, third Bone Spring play, this is our best play, has currently 3 to 4 years at our current run rate. If we never generate another idea and we had our only current land on that play alone, we have 3 to 4 years of run rate at our current drilling pace. And we're -- it's our most active lease play. We're continuing to generate activity aggressively through additional leasing. And then, of course, at Wolfcamp -- and we own -- Wolfcamp is still early. I mean my enthusiasm is because that's what I'm paid to do. I believe in our staff and I believe in our internally generated ideas and I've always liked talking about good results. But we're going to see. If that looks like what it's evolving into, that in and of itself is many, many years of drilling and it's very liquids-rich. So the Permian is a sustainable business for us. It's not something where it's a -- we're not having a going out of business sale with high activity in the Permian. It's sustainable.

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

Your proved developed proportion of reserves went up. Is that just from the sale of Riley Ridge, which is a PUD?

Yes.

There was nothing really else going on?

No, absolutely not. And everybody has their own philosophy. We try to give a lot of transparency to our assets, and we think we've got lots of things to do for many years to come.

Okay, great. Can you talk about -- you''ve talked a couple of times about reconsidering the capital allocation between Cana and Permian. Can you talk about the contractual obligations for rigs and other equipment services that would either allow you to do that or prevent you from doing that or create sort of timing issues surrounding that?

Gil, this is Joe Albi. As Tom mentioned, our rig commitments are really far and few. There are 4 rigs that we've got some type of commitment to with Cana. Those all edge off by the -- or fall off at the end of the year. And everywhere else, it's well to well. So I hope that gives you an idea of what we're contractually obligated to do there. On the service cost side, the only other type of commitment we have is for one of our frac services providers, and we've got about another year left on it. It's kind of one of these deals that we've committed to some capital level of expenditure, and if we don't meet that every month, that we can move that into the next month. So it doesn't really force us to do anything.

If -- to keep that one crew busy, how many rigs would you need to run?

Well, right now, we've just got one frac crew working in Cana.

Right. And that's the one that's under that obligation?

That is correct.

But how many rigs would you need to run to keep that crew busy?

Oh well, they'll knock off maybe one a week. So you get 4 completions a month out of them.

Yes. But I just -- I'd chime in, when we made that commitment, that's a crew that we could -- it's a [indiscernible] the Permian. So that's not it. We don't view that as a -- that would not be a factor in any decision we made.

Got you. Okay. I think, Joe, you mentioned that the waiting on completion backlog should rise about 15 by the middle of the year. Will it stay 15 or will it go down, or how does it go once it gets to that 15?

No, that was just Cana. And if you bear with me a second, I can give you a better idea for that. I think total company, we should be upwards near 25-plus. And then, of course, we'll whittle that down as the infill project matures.

Yes, we're -- again, we have some complete flexibility and it's driving our team crazy. Because our flexibility has keep those 10 rigs running, infill all 7 sections and then go to another row that we have ready to go. So we could just keep infilling Cana until the cows come home here for years to come. But we do have flexibility. We're watching these markets like everybody else is. And we're going to react depending on what the gas and natural gas liquids price dictate. We're not going to destroy capital to keep rigs busy.

And if we get backlog like we did before, we'll just pawn some additional frac crews. So part of the science of the infill is the completion and understanding how to frac in those wells not just individually, but multiple wells.

Okay. So what you're saying is that, that backlog rises or falls based on what your -- whether now you step on the gas in the Cana or not from the current plan, right?

I'd say that's a safe assessment.

Yes, Gil, you know us. I mean we're going to do what makes sense to us, and I hope everybody hears that loud and clear, that these plans we're reporting are great, but we're -- our only commitment to the shareholders is we're going to make what we think are best decisions for long-term interest of the shareholders.

Okay. And the last question is just can you talk about how we should think about the Gulf Coast in terms of -- I know that there's no Gulf Coast growing success in the current guidance. Can you give us some sense as the timing of when the seismic is going to be done, when the inventory will be in place, when you start drilling and how we should think about this potential success rates of those first wells and the new seismic shoot?

Well, Gil, this is Tom. I -- we tell you that we have a lot of new data coming in and it'll be second half this year before we even have the opportunity to talk about any kind of go-forward in inventory. So I think we've done exactly the right thing, and that's we haven't guided any Gulf Coast production. So we'll know when we get that in, what happens. And I would expect we're going to have inventory, I would be surprised if we didn't. But one of the things that we're going to try to do is space it out a little bit. I mean, we -- I mentioned binge exploration. We've always kind of been a; let's-get-it-done-as-soon-as-possible outfit, and not that we're changing our stripes there, but we're going to try -- I like the fact that we're having a few programs come in that will give us the option to kind of, assuming we have the kind of inventory we're planning, we don't have to get them done all along. So we can space that out, so it will be more manageable in terms of production. But that said, I think I'll just -- you're being horribly redundant. I mean the thing that we're all kind of excited about is we see this permanent Mid-Continent growth kind of makes this issue, to us, kind of irrelevant in terms of the kind of lower print that may have.

Your next question comes from the line of Jeff Robertson with Barclays Capital.

You all are talking about 19% to 25% production growth in the Permian and Mid-Continent in 2012 over '11 and drilling essentially the same number of net wells at roughly 165 in '12 and 164 last. You mentioned operational efficiency several times in your all's comments in different plays. Can you just talk about how much of that higher production growth rate on the same well account do you think you pick up from operational efficiencies versus maybe drilling different targets than you were in 2011?

Well, this is Joe. Built into all this, when we look at 2010 to '11 and '11 to '12, there are some timing issues that come into play. In particular from '10 to '11, if you remember, we had a huge backlog of completions in the Permian. I think we got up as high as 30 wells waiting on frac by the middle of the year. And then, of course, we pushed that hard at the end of the year. So when you -- those production results occur at the end of the year and then averaged out over the full year,are a number. I would answer this question, and Tom, chime in too, that the types of wells that we're drilling, the targets that we're drilling, the IPs that we're seeing, we're seeing some better results in the Permian. Cana is coming in as expected. It's more of a timing issue on when we anticipate the wells will be drilled and completed, and then, of course, coming online. I mentioned in my section of the call that we were, I guess, tail end loaded with accelerated production growth in 2012. Our current model is saying that maybe our exit rate, midyear, might be 6 and a quarter, 625 million a day, and with that growing hopefully to levels over 650 million a day-plus at the end of the year. So that gives you a feel for how it's hitting our model as far as it being our equivalent production estimates. I don't know if that helps you out at all, trying to understand how we've modeled it. I wouldn't say it's the type of well that we're drilling other than we are drilling some better wells in the Bone Spring area, the capital efficiency that comes into play, in particular in Cana, where we've kept our well costs in check, and we're going to optimize our drilling and completion dollars, especially the completion dollars, trying to figure out what kind of bang for the buck are we getting on our fracs to try and keep that in line.

Joe, the part of that, just going back into the core of Cana instead of doing more of the step-out drilling and getting more out of the rigs that you're working with?

Well, I think most of it's associated with pad drilling. You put 2 wells on each pad, we're consolidating services where we can, we're consolidating equipment where we can. You've got reduced move[ph] charges because you're not moving[ph] from well to well. Our facility costs are lower. We've utilized biofuel on 6 of our rigs. That's knocking off about $300,000 a month of our drilling and completion costs with 6 rigs on biofuel. So there's a number of things that we're doing there that program drilling really allows us to do and take full advantage of.

Jeff, one thing that we talk about, everybody in the industry's aware of this, when you go to a more liquids-rich program, it doesn't necessarily show up in an Mcf equivalent rate, but it sure shows up on returns. And when we look at Cana core, our -- we haven't talked a lot about Cana deep results, but we have good results. I mean we had, on average, with 19 wells we drilled, 15 of them operated that are currently on line, we were averaging 4 to 5 million cubic feet a day held flat on a slowback for 3 months or more. We're slowbacking those wells, choking them back to try to manage that downhaul reservoir pressure. So they were very, very nice wells. The problem with it is that it's methane. There's almost no liquids uplift there. So as we go to the core, we're seeing kind of comparable rates, but we're also seeing yields of anywhere from 10 to 35 barrels of condensate per million, condensate that is trucked off as oil, and then anywhere from 86 to 111 barrels of natural gas liquids per million. So the rates on an Mcfe basis don't necessarily show the difference in the return. And so it's much more capital-efficient.

But that really surfaces -- this is Joe, that really surfaces in the Permian program, too. We're directing more capital into an oil and liquids-rich area down there, and it's the same deal. An Mcfe in the Permian is not like an Mcfe in a dry gas area.

And then last question, on your -- do you have any material acreage dollars in the 2012, $1.4 billion to $1.6 billion capital number?

We do. I will say, in 2011, for us, we spent a lot of money on acreage. We spent actually about $189 million on acreage in 2011. And that's, for us, at 15% of capital or a little less than that. That's a pretty aggressive year for acreage. We would like to do that or close to that this year. Mark's looking at the numbers. What do you have modeling?

It's about $140 million for this year.

Yes. And so what will happen there, a lot of that 2011 was our pushing to Cana deep. We spent a lot of money putting the Cana deep position together. We would like to see a very aggressive acreage year, Mark's carrying $140 million, and I would say, I would expect the lion's share of that to be Permian and other new ventures. And new ventures could be Anadarko Basin.

Your next question comes from the line of Ryan Todd with Deutsche Bank.

Just a couple of questions for you. In the Permian, can you talk a little bit more about what changed in the Bone Springs wells that you've been drilling relative to the 3Q call and the results that you've seen?

Well, yes, this is Tom, mister dour from the Q3 call. The thing that I -- Chris, we never get a do-over in life. But one of the things I will say is even in the Q3 call, our returns in our Permian were very good. And I probably should have stressed that a little more. It was our actual results to our expected results. And so what changed is our teams really tore into that. We did a lot of petrophysical work, some geochemical work, and identified some more subtle trends that we had -- kind of we've been kind of drilling our way into and we really tore the wells apart, built some water saturation models. The operations group did a great job of getting some saltwater disposal in place that will allow us to make money moving this water instead of hauling it and really drilled some nice wells. We are not here today talking about individual wells, but I will say, we did drill some wells in the fourth quarter that averaged, for first 30 days, averaged over 1,000 barrels of oil equivalent per day. And that's through that science, we moved into some areas that we think are just better. So that said, we upsized our fracs. We had some nice results in the Wolfcamp once we completed our wells. So there were so material changes in our program. I mean we're always focused on getting better at the business, and in the third quarter, you kind of caught us in the middle of it. And I will say, today, we are better at the business.

That's great. And if we look at the Permian overall, I know you talked about the line that you installed there down the Culberson County. From an infrastructure point of view, do you see any potential bottlenecks on the system anywhere in the basin? And if so, what regions do you think are going to be tightest, both for you, and I guess, for industry in general?

This is Joe, Ryan. We've put in about -- I think at the end of the year we had over 67 miles of infrastructure, mostly pipeline in place in the Permian. Our goal was simply to control our infrastructure, obviously, and give us some market optionality. We're worried about takeaway capacity on the Permian as I know all of our competitors are. We've put in our own tap into an El Paso line that we will be JTing our own production. That gives us a little bit of a reservation, if you -- capacity, if you want to call it that. And we're also working with the likes of, I won't name names, but other processors to understand what they have coming around the corner in the area and what capacities they currently have to try to ensure to the degree that we can that our volumes are moving. We see the El Paso tap as kind of being our safety net where we may not get as a good recovery out of our JT, but we certainly will be able to move the gas.

Okay. And I mean I know trucks were -- at one point early in 2011, there was kind of tightness in trucking and then had loosened up. Does that kind of remain not much of a concern these days, or is that still a concern as well?

I want to give kudos to our marketing and operations guys who've done a great job there. We find ourselves up with a couple of purchasers, where there's scorecards in place, certain processes in place to ensure trucks are available. We've put a deal together for the piping of some oil out of the West Texas area with some commitments on their part, to the hauler's part and ours, that we will both perform. That has certainly helped. And that really picked up in Q4. We had a little bit of a problem with the weather in December, and then we made all that back up just tremendously here in January. So the guys have done a great job there.

Great. Then one more, if I could, on Cana. The range that we see in the production guidance for 2012, is that primarily driven by potential for flexibility around that Cana program? And if you decide not to go forward with kind of the next leg of drilling there, pad drilling in Cana, does that take production to the low-end of the guidance range or how should we think about that?

We've built out around the current 10-rig program. So to the extent we accelerate or decelerate, it would affect those numbers. But if we decelerate, as Tom mentioned, we'll be moving that capital elsewhere.

Yes. And because of the delay on those completions, that really would not impact 2012 significantly.

And more impact...

In 2013, right. If we were to keep going, almost by the middle of third quarter, anything we do from then out shows some 2013 production just because of the -- there's a natural delay when you drill these wells side by side. You have to get a certain bank of them drilled before you complete them.

Your next question comes from the line of Joe Allman with JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: So just to clarify and following up with Ryan's first question, so what is it that explains the higher IP rates on average for both the Wolfcamp and the Bone Spring from the third quarter to the fourth quarter? I mean, is it geography? I mean, did you just drill in different locations where you got better rock or is it more fracs or longer laterals? I mean what is it really?

Yes, well it's -- there are -- that's 2 different areas and there's 2 different answers. In the second Bone Spring, it's -- a lot of its geography, we, through our analysis of the petrophysics, stayed out of some of the higher water-cut areas. We also upsized our completions. And so that -- some of it is geography, targeting what we saw as richer areas, and some of it is upsizing our completions. So it's a combination of both. In the Wolfcamp, some of it's just the real estate. I mean we're drilling our way through and we've tried targeting a couple of different stratigraphic intervals. One of the things that we see in that Wolfcamp play is -- and we talked about this in the very beginning. We don't understand the variation until we get out there and drill it. There's not a lot of wells to key off on, where we have mud logs. And so one of the big variables is going to be yield, how much condensate are you going to make, what's the natural gas liquids yield. And so we're out there drilling and testing the area, and we're finding that, I think, we're identifying a couple of sweet spots out there. So, Joe, it's kind of a combination of both, operational efficiencies and real estate. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay, that's helpful. And so in the third quarter, when you talked about different issues, you talked about, I think, some lower EURs than you previously have modeled. I think you talked about water handling and that caused the cost to go up. I think more water than you had modeled. And then you just talked about general cost pressures. So could you just address those issues and do you see all of them resolved, or which ones do you see resolved and which ones are still unresolved?

Yes. The water issue is -- if you drill into an area with high water cut, you're going to make water. I mean if somebody has a way to fall -- fix that, give me a call. But you can mitigate it by saltwater disposal. And in the third quarter call, we were in a situation where we're paying at times, $4 a barrel to haul water and that could just kill your economics. So we've gotten saltwater disposal wells in, and we've also, by this petrophysical work we've done and working with our operations group, have a plan in place where we can go in and target these high water cut areas, but have a disposal well ready so we're flowing back into a saltwater disposal well. But I'm looking at a -- right as I answer your question, I'm looking at kind of a highlights reel of the fourth quarter in that second Bone Spring. And I will say that our water cuts vary from 29% upwards of 65%. So even at 65% water cut, you can make a nice living if you can dispose that water efficiently. So I wouldn't say we've solved the water issue and that we're still going to make a fair amount of water in that play, but we've done a lot in terms of fixing the economics of it. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay, that's helpful. And then in terms of service cost pressures, I think on the third quarter call, you talked about service cost pressures especially in the Permian. And if I'm hearing you correctly today, you're talking about costs going the other way in the Permian.

Yes, that's a tricky question. This is Joe. With regard to fracs, the frac has a number of components. You've got your service costs, and that can be affected by the cost of their personnel, number one, and to some degree, our efficiencies in getting a job pumped. If it takes us less time to pump a job, the service cost is less. On the service cost side, we have seen the per unit cost go down. You've got the other 2 ingredients. You've got fluids, and those can vary by the degree to which we use more fluid and the type of fluid that we use. And then on the prop side, what type of prop do we use? We've worked very hard to use white sand where we can, and for the most part are using it in virtually all of our operations. That's helped cut our cost down on the prop side. But if we run more stages, we're going to run more -- we're going to pump more prop and more fluid. So overall, I'd say, as a company, that quarter-to-quarter, we've seen our overall total company service costs go down. And the fluid and prop costs are probably in that flattish range as a result of how we may or may not have changed our program design. Joseph D. Allman - JP Morgan Chase & Co, Research Division: And Joe, just speaking specifically to the Permian, so you're seeing the, that overall costs go down there as well?

Yes, right now, it's starting to soften on the service side. The biggest controlling factor there is do we pump x number of stages or y, with y being more than x, the total volumes pumped. I want to elaborate a little bit too on what Tom said about the SWD issue and how that affects not only our lifting costs, but the economics of these wells and particularly, the Permian. We really got going on that, I'd say, in late Q3. Some of the results of those SWD projects we'll see in our lifting costs being reduced from current levels on the SWD side. But our real goal is to get out ahead of this thing so that those costs never even hit the books and that we're paying virtually little, if any, dollars to dispose of any of the produced load water that we see from our new wells. We have identified, at the end of the year, 17 different SWD projects that entail about $40 million worth of capital that we're trying to undertake that hopefully we'll have done here before the end of the year. Some of them have already been completed. But we're really emphasizing that, and that is really having an impact in our overall rate of return in the Permian, number one, and that, number two, we hope to have it show up in our lifting cost.

Yes, Joe, this is Tom, and we -- you know us well. I mean we'd rather talk about results than promise, and we're really happy to be here this morning talking about real results. We haven't had our last problem solved. We're a blocking and tackling outfit. We try to do good science, be good at the business, but we certainly like where our Permian and Mid-Continent assets are sitting right now. We're having really good results. And I think that the program we've outlined here today has a great promise to deliver those results. And another thing that we're really pleased to report to you is we have flexibility. If there's ever a time in our business where I've looked out at the future and thought that the boundaries are broader than I've ever see. In terms of up and downside of people's forecast, we have flexibility, so to be able to react, to run for daylight or pull in a little bit, depending on market conditions. So we'll continue, hopefully, to report good results, but we've had some very, very nice results in both the Permian and our Mid-Continent programs. Joseph D. Allman - JP Morgan Chase & Co, Research Division: That's helpful. And just one more, and I think this is for Joe. So, Joe, In the Gulf Coast, basically, your guidance is suggesting that you're going to be down about 50% from the fourth quarter production level to the average of 2012. So that's all that midyear. Is that -- are you guys just being conservative with that?

Well, Joe, we've got -- we're always fighting some of the same old things with mechanical issues or sand flow or what have you. But what I have attempted to do, both approaching it from 2 different angles, is look at potential risked contribution from new wells without a lot of mechanical issues. And what is that number for Q4, what is it if you just assume nothing and, from the new wells drilled and no mechanical issues, and we still come around that same darn level that we've quoted in our press release. So I really don't know how to say any more than that.

It's our best estimate.

[indiscernible] Yes. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Anyway, but I guess it's interesting that the production, even though you've -- it would seem to me that you've gone through the steepest part of the decline and the decline would lessen, that the number suggested is going to be down 50%. And that's 50% from fourth quarter to maybe midyear.

Yes, that's what we're modeling. Most of that solved the Beaumont stuff. And we've got some assets that are fairly longer live. I guess you want to call that for the Gulf Coast that eventually, that will tail off and that decline won't be as severe. But in our minds, the point of the matter is, hey, it's less than 6% of our total production in 2012.

Gentlemen, do you have any closing remarks?

Oh, yes. Thank you, everyone, for joining us today. Appreciate everyone's participation in the call, and we look to continue to report good results in the future. If you have any follow-up questions, please don't hesitate to give us a call. Have a great day. Thank you.

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