先鋒自然資源 (PXD) 2012 Q4 法說會逐字稿

Welcome to Pioneer Natural Resources fourth quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President of Investor Relations. Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors, then select Earnings and Webcast. This call is being recorded. A replay of the call will be archived on the Internet site through March 11.

The Company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on page 2 of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission. At this time for opening remarks, I'd like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.

Good day, everyone. Thank you for joining us. Yesterday, Pioneer issued a press release announcing an underwritten public offering of common stock. We will not be able to discuss that offering on this call or take any questions about it. But I refer you to our press release and the prospectus filed yesterday with the SEC if you have questions or would like information about the offering.

On today's call, which will have a hard stop at 10.00 AM Central Time, we will be discussing our fourth quarter financial and operating highlights and our plans for 2013 through 2015. More specifically, today's agenda will first have Scott provide the financial and operating highlights for the fourth quarter of 2012. He will then review our capital program for 2013, our production growth outlook, and the extremely encouraging results we're seeing from our horizontal drilling program in the Permian.

After Scott concludes his remarks, Tim will discuss our horizontal drilling plans in the Permian, both in the southern Wolfcamp joint interest area, and across Pioneer's extensive northern Wolfcamp/Spraberry acreage position. He will also update you on Spraberry vertical, Eagle Ford Shale, Barnett Shale Combo and Alaska operations. Rich will then cover the fourth quarter financials in more detail and provide earnings guidance for the first quarter. After that, we will open up the call for your questions. So with that, I will turn the call over to Scott.

Thanks, Frank. Good morning. I will start off on the financial and operating highlights on slide number 3. On the fourth quarter, we had adjusted income of about $107 million, or $0.83 per adjusted share. Production, including the Barnett by bringing it back in from discontinued operations, fourth quarter of 165,000 barrels of oil equivalent per day. Without Barnett, we were at the midpoint of our guidance range at 156,000 barrels of oil equivalent per day. For the full year, we've averaged 156,000 barrels of oil equivalent per day, including the Barnett Shale production. It is up 29% for the year, versus '11 which is the top end of our full-year guidance range.

We're also up 54% in oil growth over -- since 2011. The growth attributable to strong programs from the Spraberry vertical, horizontal Wolfcamp Shale program, the Eagle Ford and the Barnett Shale Combo drilling programs. We released our finding costs and our reserve replacement just last week, delivered over 250% drillbit reserve replacement, 161 million BOEs at a drillbit F&D cost of a little less than $18 per BOE, $17.72. We are initiating a $1 billion horizontal drilling appraisal program at Pioneer's northern Wolfcamp/Spraberry acreage for 2013 and '14; $400 million of that is included in the 2013 drilling budget of $2.75 billion, the remainder, $600 million, in 2014.

Long term -- or short term for 2013, we're forecasting a production growth of 12% to 16%. If you look at the slide later on, we are backing out a sale to Sinochem about mid-year of a little bit over 4,000 barrels equivalent per day. That would have moved the rate up somewhere between 14% to 18% for the year of 2012 to 2013. Long term, also, using an $85 flat price deck for WTI for the next three years, up to $100 WTI flat for the next three years, we're targeting a 13% to 18% compounded annual growth rate from '13 to '15. We will go over more the back-up for that when we get to the growth slides.

Slide number 4, drilling highlights. Really, we feel like this is probably the most important quarter in the Company's history for a couple of items. One, we have brought on what we feel like matches our geoscience maps, the best well in the horizontal Wolfcamp Shale play in the B interval, in Midland County. That's essentially 1,700 barrels of oil equivalent per day in IP rate and a peak 20-day average flow rate of over 1,500 barrels of oil equivalent per day, 75% oil. This well is 25 miles north of our best two wells in the south in the Giddings horizontal Wolfcamp Shale wells which we will comment on later on and update on those wells.

Obviously, the second thing that happened during the quarter was putting a value on our southern acreage of $21,000 per acre, and selling roughly about 10% of Pioneer's total Wolfcamp acreage position. We announced a $1.74 billion transaction with Sinochem, and that transaction is expected to close the second quarter of 2013. In addition, we had tremendous results in our JV area with a -- joint interest area with Sinochem. We drilled our first 10,000-foot lateral in the Upper B interval in Reagan County, with an IP rate of a little over 1,200 barrels a day equivalent with a peak 20-day average of a little bit over a 1,000; 80% oil.

Also if you recall, we've been showing in our maps the last couple of quarters that the B interval is thick enough, up at the 500-, 600-foot range that we're still -- we feel like that's going to take two wells to drill up the B interval. We drilled our first Lower B interval well, came on, and is currently producing way above the 575,000-barrel type curve. We've also drilled our best Wolfcamp Shale A interval well, which is the top of the Wolfcamp, also producing above that curve.

We're targeting -- we did achieve our targeted year-end '12 horizontal Wolfcamp Shale production of 5,000 barrels a day that we had brought up during the last quarter. In addition, we increased our net resource potential, primarily from the Midland County well and the data that we have put together, up from 5.7 billion barrels of oil equivalent per day, up to about 8 -- or greater than 8 billion barrels of oil equivalent per day. We will comment on that as we get to the slide and talk about the back-up that makes up those numbers.

Going to our capital budget for 2013, we're announcing a capital program of $3 billion. That does include $2.75 billion from drilling capital, and roughly $240 million from other items which I will talk about. We do have cash flow of roughly about $2 billion in an $85 market, $600 million will be coming in about mid-second quarter from the joint interest cash proceeds, then $400 million from capital markets.

The primary expenditure, obviously, is in the Permian. We've got $1.2 billion in the northern Wolfcamp/Spraberry area, and the Spraberry area, made up of the $400 million for the horizontal program; $625 million essentially for 15 rigs, vertical rigs running that are essentially holding leases that are on continuous development; and then $200 million for infrastructure automation. That does include salt water disposal wells, additional gas processing plants, and automation.

On Eagle Ford, if you remember, the carry ran out last November so the expenditure has increased significantly. It is cash flowing, the asset now, with the carry expiring more than our capital. We're at $575 million there. And then in the Barnett, we will be running two rigs over the next three years, with $185 million, with continued significant growth over the next three years.

The $240 million of other capital, as we had mentioned, over the past several quarters, obviously, a big decrease in vertical integration. We essentially are through building things out there, of $25 million. We are expanding our sand mine, up to $70 million to account for the significant increase in the horizontal Wolfcamp, both in the joint venture and also to the north, and then $145 million in building field offices and others. That's, again, primarily mostly going to be pumping services, new offices, and also field offices, and about $52 million of that is in a Midland building for our employees out on the north side of Midland.

Turning to slide 6, in going over our growth rates and what makes up those growth rates. Again, we're targeting 13%, 18% compounded annual growth rate for the next three years. That's in a range of $85 oil flat for WTI to $100 oil flat for the next three years. Again, we do have the sale to Sinochem, a little bit over 4,000 barrels a day equivalent. We're estimating about June 1 on that. So that's why we have a lower 12% to 16% for 2013. Again, we end up about 60% liquids for fourth quarter, going to 70% liquids for 2015.

In addition, we are not -- in this number, we are not modeling the Hutt-type curve, which the well came in 1,700 barrels a day. We are modeling in this growth profile, essentially a 500,000-barrel type curve to 575,000-barrel type curve. So we are very, very conservative in regard to not using the Hutt-type well, which we expect more wells in that range as we ramp up the rig count to the northern appraisal program.

Going over a few of the details on our announcement in Midland County well, on slide number 7, again, we've outlined three critical items in this type curve. We got barrels of oil equivalent per day on the left side, and time on the right.

Start off with an update on the Giddings wells. If you recall, they've been our two best wells in the northern part of our joint venture area to the south, the 207,000 acres. The two wells if you notice, they now have been put on artificial lift, one pumping unit, one gas lift. They're performing -- they're starting to perform above the type curve, so above the 650 type curve. Those laterals were at 5,300 feet. 2013 drilling, we will focus a lot more wells in this area. In addition, the Hutt well to the north, it came on 1,700 barrels a day equivalent, averaged 1,500 barrels a day equivalent, essentially twice as much as the Giddings wells.

So we, obviously, haven't put on a type curve, but it -- obviously, it implies a significant increase way and above the Giddings for this Hutt well. It also confirms our maps that our geoscientists have built over the last two years. In addition, we saw a 40% increase in the University well 4H -- 10-1 #4H in our first 10,000-foot lateral. We have several more that are in the works, at 9,000 to 10,000 feet. But this well came on 40% greater than the Giddings wells at a cost of about $1.6 million. So again, tremendous economics on all of these wells.

Going to the next slide, an update on our announcement last quarter of the horizontal Jo Mill. The Jo Mill is a sand that we've been perforating over the last 40 years in both the north and the southern acreage. We did drill two wells in northern Upton County. We [called and] announced them last quarter, an update on those. We normalized this. If you recall, they were drilled 2,500-foot laterals. We normalize it to 5,000-foot laterals, is what we expect to drill on our appraisal program to the north over the next two years.

More of our wells is going to be in the 5,000-foot range in the Jo Mill and also in the Spraberry Shale. But you can see, both of these wells are performing way above the 650 type curve. Also we expect the well cost to be probably $1 million, $1.5 million less as we drill in the Jo Mill and the Spraberry Shales than the Wolfcamp. So again, we're very excited about this.

Going to slide number 9, this is one of our treasure maps that the geoscience team has built over the last two years, just indicating with thousands of wells -- hundreds of wells of core data and well log data, thousands of wells that we drilled in this area. So we have a lot more data points than just having two wells in Midland County. We do have the well located in the middle of Midland County, about 25 miles north of the Giddings wells. In addition, we point out a third-party well that IP'd at 890 barrels a day, and not too far from our Hutt wells on the western -- northwestern side of the Midland County, with 3,700-foot lateral length.

We do have two wells up in Martin County, but you can look at the vast amount of acreage, is in what we call Tier 1, a lot of data went in to build this. We feel like with the higher reservoir pressure, the temperature, the better thermal maturity, higher organic content, which is the kerogen content, enables to show tremendous results going forward in this key area. It is important to note that Tier 2, several wells have been drilled by us, and other operators, in Tier 2. It is also expected to be very productive and economic.

Finally, on slide number 10, an update on our resource potential. Our proved reserves have been update -- up to 1.1 billion barrels of oil equivalent. Both resources up over 9 billion barrels of oil equivalent, over 40,000 drilling locations. But the big changes you will see on the right side, in the Wolfcamp play. Obviously, we did sell from previous reported numbers, we did sell -- when we closed with Sinochem, roughly about 1 billion barrels of oil equivalent when that closes. So our southern area obviously went down with that sale. Our northern area, obviously, is continuing to go up.

The key here is we're only using roughly 500,000 barrels of oil equivalent to come up with our estimates of the 3 billion barrels in the north. We're not including any Spraberry Shales -- the two Spraberry Shales, both the Middle and the Lower Spraberry Shales. We're also not including any downspacing. All of this is calculated on 140-acre spacing. We are drilling our Eagle Ford and our Barnett down to 70-acre spacing now so we get essentially double the upside in all of these key areas in regard to the resource potential. Let me stop there now and turn it over to Tim to talk more details about the budget and operations.

Thanks, Scott. On the next several slides, I'm going to try to give you some granularity on our activities in our main areas of drilling. First, I'm going to focus on the southern Wolfcamp joint interest area. It is, of course, the subject of the recently announced signing of the agreement with Sinochem. In that area, we -- as shown on the map, we've drilled some important wells. Scott has already alluded to these wells. This is the first of the Lower B wells, also the 10,000-foot lateral well he mentioned. That well has really been phenomenal; it has made 31,000 barrels in its first 34 days of production. So it is a phenomenal well. And then, of course, our first -- one of our A wells being very successful in that area as well.

So the drilling campaign is doing exceptionally well, with seven rigs running. As anticipated, related to our Sinochem announcement, we anticipate increasing that rig count to 10 rigs next year, and then about 13 rigs in 2015. As shown there, that will ramp up our drilling of wells to 86 this year, up to 120 next year, and about 165 in the subsequent year. That's all as a part of the agreed to work plan and budget with Sinochem.

Our 2013 campaign will continue to test multiple intervals, A intervals in the Wolfcamp, Upper and Lower B, as well as D. We're still looking at about $7.5 million to $8 million cost to these wells, for an average 7,800-foot lateral. Of course, that won't include some 10,000-foot wells, one of which we've already drilled, and we have another soon to be put on production. As Scott mentioned it is a $1.5 million to $1.6 million, but we're also looking at substantial increases in productivity, probably 40% increases in productivity. So we continue to see an essentially linear relationship between productivity and lateral length.

We are going to continue to optimize our completions. That's, of course, a requirement in these shale plays to look for continuous improvement. One thing we are trying is what some offset operators have tried -- have used for some time, and that is slickwater fracs. We have one well on flow-back that we've used slickwater, and one that is yet to be completed. But suffice it to say, there is substantial savings for slickwater fracs as compared to gel conveyed fracs that can range from $800,000 to $1 million per well, which means it could have substantial benefits across the entire program. We do continue, of course, in this area, as we're drilling some new areas to have at least some science cost continuing, probably about $20 million this year, and of course, that's for microseismic cores, log suites, and so on.

As you look forward to 2014, and beyond, we will be more focused in the southern area on development drilling, so you can expect a lot more pad drilling. So going to about 75% pad drilling versus about 50% this year. As Scott has already alluded to, the work will be done to evaluate how far we can downspace this field, in which case we are just adding significant opportunities. The objective is to take the spacing perhaps as low as 70 acres.

Let's go to slide 12 then, and let's turn to the northern acreage. Of course, it's a major objective of our 2013 drilling campaign to prove up the prospectivity of the Wolfcamp and the Jo Mill and the Spraberry Shales in this vast area. Currently, we only have one rig running. Of course, the plan is to increase that to four rigs early in 2013's second quarter. We have drilled our first two horizontal Wolfcamp Shales in Midland County. These are the ones Scott referred to as being about 25 miles north of the successful Giddings horizontal wells. These wells have been -- this Hutt well has been absolutely phenomenal. It is a B zone well. It has made 40,000 barrels in its first month of production.

Similarly, as you look at the [cume] wells when it comes to Giddings, they're phenomenal as well. After about 16 months, they produced 160,000 barrels of oil equivalent. So these wells are really outstanding and we continue to see the prospects that as we go to the north, we can have some outstanding well results. The second of the DL Hutt wells is an A well, and we're -- it is in the frac bank waiting to be fracked. We now are -- as Scott mentioned, drilling a couple of wells in Martin County. Those are Wolfcamp B wells and we will have more to report as those wells are put on production in the next few months.

All of this, of course, is based on our substantial amount of data. We've drilled 7,000 wells out here. We've done substantial petrophysical analysis on some 900 wells. It is tied to thousands of feet of core. So we have a very good handle on the prospectivity of all of these zones throughout the acreage. And the objective, of course, in the north is to accelerate our understanding regarding the various zones and I will talk more about that on the next slide, slide 13.

As shown here, we will be targeting, in our 2013 drilling plan, about 30 to 40 wells in the north; about half of those, 15 to 20 wells, we will target the various Wolfcamp zones, A, B, and D, in addition to which we will drill a similar number of well, something like 15 to 20 wells, to test the Jo Mill, which has already been the subject of two wells, as well as a Middle Spraberry Shale and a Lower Spraberry Shale. The Jo Mill wells have actually produced phenomenally well, as Scott has mentioned as well. Actually, they average about 37,000 BOE, having only been on production for about four months, which is substantially more than a typical Jo Mill well will contribute to a normal vertical producing well.

So as we look ahead, again, we're looking at probably $7.5 million to $8 million well costs for 7,000-plus foot laterals. Recall, we are deeper drilling as we go north. It is important to note in the campaign for 2013 that we have substantial new infrastructure needed to deal with the substantial production volumes and liquids volumes that are coming from the new wells. I mean, it is really an order of magnitude increase in the amount of liquids we're handling. So we need substantial investment in new tank batteries, flow lines, salt water disposal, and so on. We estimate that's about $80 million for 2013, and perhaps a similar amount for 2014, as we ramp up the program in the north.

As shown on slide 14, it is really, in our case, about connecting the dots. You can see here, a broad map of where we plan to appraise the various areas of our acreage, including in Martin County, and Midland County, Gaines County, and so on, in the north. The objective is to drill wells, totaling capital of about $400 million, and about $600 million in 2014, in all of these areas. What we're, of course, chasing is these six intervals, including the three Wolfcamp intervals, one Jo Mill, and two Spraberry Shales that I showed on the earlier slide.

If you consider that across these stacks, [that has you] about 600,000 acres of plan view, that means we're really dealing with something that's 3 million gross acres when you consider it in 3-D perspective, due to the stacked intervals. We believe from the information we've already divined from all of the science work I've mentioned, that we have about 3 billion BOE of resource potential in the north. It will take about $1 billion to demonstrate that in the next couple of years, and that actually excludes the Spraberry Shale zones.

It looks like we will exit 2013 with about 5,000 to 7,000 BOE net of horizontal production. Of course, our production is back-loaded in 2013, simply because we're just in the process of ramping the rigs up. It is the case that the horizontal wells take a longer time between when they're spud and when they're put on production. Our average is running 120 days, where vertical wells are more like 70 days. So that has the effect of skewing production to the back end of the year. We do, however, believe, and continue to believe, that horizontal drilling is more capital efficient than vertical drilling. So that's why we're heading more capital towards the horizontal campaign. Where we are going to be four rigs this year, we plan to be about six to eight rigs next year to drill the wells I mentioned and to spend the $600 million to appraise the program.

In addition, although we haven't gotten specific details on this, we will eventually be testing deeper horizontal zones. We think it has already been proven there's substantial opportunity in the Atoka for horizontal drilling. That has been proven in Martin County by other operators. But we will also look to, perhaps, test zones that are deeper than the Wolfcamp in addition to the Atoka, such as the Woodford and the Barnett and the Mississippi. But suffice it to say, what we are trying to do here is to spend roughly $1 billion in the north over the next couple of years, the objective being to confirm about 3 billion barrels of resource potential and in doing so, add substantial value. We're very confident that that is going to occur over the next couple of years.

Turning to the vertical program, lest we forget, the vertical program is that which contributed to our excellent production growth in 2012. We will be continuing a vertical program, albeit it at a smaller rig count. We will be drilling with only about 15 rigs this year in 2013, drilling about 300 wells. Scott already mentioned the fact that the reason we are landing on 15 rigs is that we have continuous drilling obligations on many of our leases. By drilling wells vertically, we not only preserve the leasehold but we also preserve the deep rights that will be the subject of future horizontal drilling in the Wolfcamp and other zones.

We are, as a result of the success we've had in the past, deepening the vast majority of our wells. In fact, as you look at 2013, this year, we plan to deepen about 90% of the wells into the Strawn, Atoka, or the Mississippian, as the case may be. This was already mentioned, but we have a -- we're expecting at least to drawdown our frac bank. We did build somewhat of a frac bank at the end of 2012. I will comment more about that in just a minute. Suffice it to say, though, we think drilling deeper is really the key to the economics and the productivity of our vertical campaign.

Turning to slide 16, this is kind of summing up the impact of all of the activity I mentioned in both 2012 and 2013, where we expect, over many years, that production will grow substantially in the Permian Basin. We did come in at the top end of our range in the Permian Basin for the year, about 66,000 BOE. The fourth quarter was relatively flat compared to the third and that's because on the one hand, we were reducing our vertical rig count as we were shifting to a higher component of horizontal drilling in the mix. As I already mentioned, we did increase our frac bank in relation to vertical wells, mostly because we were shifting to more capital intensive horizontal drilling. We do anticipate that as we go forward, we will be growing this asset substantially, 14% to 21%.

We think most of the issues that we dealt with in the fourth quarter related to ethane recoveries at our gas plants in the Permian Basin will be resolved, beginning April, as we bring on another 200 million cubic feet a day facility to increase our capacity there, to 460 million cubic feet a day. So we think this issue pertaining to reduced ethane recoveries will be resolved shortly.

We do expect that horizontal production will increase, needless to say, as we ramp up in both the north and the south. It averaged about 2,000 barrels a day in 2012 and I anticipate it's going to be 11,000 to 14,000 barrels a day this year. That's, of course, reflecting the joint interest transaction with Sinochem being effective on June 1. So in summary, the Spraberry Trend Area and the Permian Basin in general, both horizontal and vertical should really provide outstanding opportunities for growth and value adds many years into the future.

Let me turn on slide 17, the Eagle Ford. Our drilling campaign continues there, and we're consistently setting new records for production. We drilled about 30 wells in the fourth quarter, put about 37 on production. We expect to drill a similar number of wells this year as we drilled last year. But because of efficiencies, both in terms of the number of days on wells, also translated to the amount of feet per day that we're able to drill, increasing, and the fact we're going to about 80% pad drilling, not only will we save money related to those activities, but also we will be able to drill the same number of wells as we did in 2012, with 12 rigs, with only 10 rigs in 2013.

We will continue to push the limits in terms of the use of white sand as a profit, replacing ceramic sand, anticipate the program will be over 50% white sand this year. Of course, there is a dramatic cost savings related to fracking these wells with white sand as compared to more expensive ceramic.

We are increasing the lateral lengths. We're doing an exhaustive study of improvements and completions. One thing we will be doing related to that is increasing the lateral lengths from about 5,700 feet on average last year, to about 6,200 feet this year. Of course, that does increase the cost per well, probably in the neighborhood of $500,000, but the data shows it is well worth it. The returns on the extra 500 feet are very strong. Still looking at $7 million to $8 million well costs, especially as we increase the lateral lengths, netting out the cost savings from pad drilling.

We're substantially complete, building our central gas processing facilities, or CGPs. We will add one more by the end of 2013, and perhaps one in 2014, but essentially our infrastructure build-out is nearing completion in the Eagle Ford. This asset really continues to deliver. You can see on slide 18, where we continue, as I said, to set production records. This asset, similar to the Permian Basin, also produced at the top end of our guidance range for the year at about 28,000 BOE, strong fourth quarter production. We anticipate strong growth going forward, as you can see, expect 36% to 50% growth into 2013 compared to 2012.

On slide 19, as was contemporaneously announced at the time of the Sinochem joint interest declaration, we have decided to discontinue the efforts to divest of the Barnett Shale assets. The bottom line is the bids were really, in our opinion, not reflective of the value of the assets. In fact, the values we received in some situations were less than what we considered to be the PDP value. We got very little value for what we think is very valuable acreage and drilling inventory. So we have decided to retain these assets and have returned those to continuing operations. We will maintain a drilling program to retain the acreage.

We did put several wells on production in the fourth quarter and we anticipate that, going forward, as we move from a one-rig count, where we currently are, to a two-rig count next quarter, the objective being to hold high-graded acreage. The returns here are still very good. They're, plus or minus, 25%, pre-tax returns, so this drilling does make sense for us. The objective is to retain our best acreage, that is to say, the acreage with the most liquid-rich opportunities. That would be something like 45,000 acres out of about 65,000 acres that are currently not held by production.

We are seeing dramatic increases in the efficiencies. In fact, we have about a $3 million target for drilling costs for these wells, and we've seen several wells drilled substantially below $3 million. In fact, some of these wells are being drilled in seven and eight days. So we really believe that this Barnett Shale asset, as we drill it out, is really going to add value. As you can see it, it is increasing production as a result of these activities.

Finally, I'll talk about Alaska. Of course, production was relatively flat in the quarter. But really more importantly, in Alaska, is that there activities that we have underway, the first of which relates to a frac program. You'll recall last year, we had a really phenomenal well, as we put in place a -- your typical lower 48-style frac on a Nuiqsut well that made 5,600 barrels a day. That well is still making 2,000 barrels a day on a flat line. So it has been a tremendously strong well. Accordingly, we're planning to frac four more wells, one of which is in the Torok formation, and three in the Nuiqsut. We are currently mobilizing the equipment out on the ice, and the first frac should commence in the next couple of weeks. We anticipate finishing that program when we're off ice, probably mid-April.

Importantly, we now have put the Nuna 1 well, which is our first Torok well drilled last year, back on production. Last year, it made about 200,000 barrels with facility constraints. We're still somewhat facility limited, but that well was testing right on 2,800 barrels a day, so it looks very, very strong. At the same time, we are drilling an offset well, that's the Nuna 2 well, to this first well and it will also be fracked. We should have more information on it, and pending the results of these wells, we're moving ahead, looking at a FEED study to evaluate a future development in the Torok in the south from onshore.

So I'm going to stop there. Suffice it to say, 2013 is shaping up to be a very strong operational year for us. With that, I will pass it over to Rich for a discussion of the fourth quarter financials and his outlook for the first quarter.

Thanks, Tim. I'm going to start on slide number 21. As Scott mentioned, net income attributable to common stockholders was $29 million, or $0.22 per share. It did include unrealized mark-to-market derivative gains of $14 million after tax, or $0.11, and then unusual items totaling $92 million, or $0.72, primarily related to a non-cash impairment charge related to our Barnett Shale assets that we moved back into continuing operations. So adjusted for those items, we are at $107 million, or $0.83 per diluted share.

Looking at the bottom of slide 21, we show fourth quarter guidance in the first column there. In the middle column, we adjust for the unrealized mark-to-market derivative gains, unusual items and Barnett Shale, to get an apples-to-apples comparison. You can see there that, basically, we're within on the positive side of guidance, with the exception of G&A, which includes performance-related compensation that were in the fourth quarter. All of the other items were in the middle of the guidance or on the good side.

Turning to slide 22, price realizations. Looking at the green bars, you can see that oil was down 5%, in the fourth quarter from the third quarter, to just under $84. NGLs continue to be fairly flat, running still 35% to 40% of WTI oil prices. Gas, you can see there, we were up 22%, up to $3.20, for the fourth quarter. At the bottom, you can see the impact of VPPs; during the fourth quarter, that is, the end of our VPPs, so we don't have those any more going forward. Then for each of the fourth quarter, you can see that we had positive impact from our derivative portfolio, adding to our overall prices when you include derivatives.

Turning to slide 23. Production costs, we're down 6% to $14.62 for the quarter. As we talked about in the third quarter, the third quarter was high, because of extra hauling costs for salt water disposal, electricity costs, and repair and maintenance. Those have all reversed and are down in the fourth quarter. We did add disposal wells that we talked about during the fourth quarter. We've got more planned for '13, which will help bring overall production costs down further.

Turning to slide 24, first quarter production guidance of 165,000 to 170,000 barrels of oil equivalent per day. It does reflect, as Tim and Scott mentioned, that the processing facility is still impacting us, 2,000 to 3,000 barrels a day for the first quarter but then should be back up and running with the new plant capacity in April. Production costs at $14 to $16 per barrel, and then the remaining of the items here all consistent with the fourth quarter, so I won't go through those individually, but they're there for your review. So Vicky, I think at this time, we will go ahead and open up the call for questions.

(Operator Instructions)

Doug Leggate with Bank of America Merrill Lynch.

I've got a couple of questions, please. Scott, you talked about the -- or you gave us some great color, I think, on the Tier 1 and Tier 2 acreage. Can you help us with -- is there any difference between the two in terms of what is prospective for all four Wolfcamp zones? It is probably a little too early but is there any specific differences you could share between your expected EURs from the wells? I'm guessing it's a little early for that, but I've got a follow-up, please.

Yes, obviously, the Wolfcamp B is the focus. We haven't put a type curve on the 1,700-barrel a day wells, the Hutt well, but it looks like it is tracking twice as much as the Giddings reserves. So, it could easily get to 1 million barrels or higher. We would expect, since we're in the center part of the basin on most of our acreage, that the Wolfcamp B is going to be the driver.

The Wolfcamp A, throughout the entire interval, is -- actually has more oil in place. It is a little bit lower pressure than the Wolfcamp B, as we frac into the Wolfcamp A, and go up into the Dean formation. So it's got huge potential, but right now, we just don't know the upside in regard to the A. We have -- the offset well to the Hutt well is a Wolfcamp A. We expect to frac it in the next few weeks. So we should have information over the next two or three months on that well.

The Cline, if you remember, we drilled a Wolfcamp D, a Cline well, back -- it was really our first well in the Wolfcamp play. We drilled in the center of Midland County. It turns out that well has flattened out, very, very short lateral. When you normalize it, it looks like the Cline, or the Wolfcamp D, is going to be up somewhere at 500,000 barrels, or 575,000 or higher.

So we are excited about the Cline also in the D -- or the D. That's where a lot of people on the eastern side of the play are drilling. The Wolfcamp A and B gets thinner; it is not as rich organically on the eastern side of the play. That's why they're focused on the Cline. We're focused more on the B, because it has tremendous oil in place, good reservoir pressure. We will eventually move to the A, and then eventually move to Cline in the northern appraisal program.

Great, thanks. My follow-up is really more strategic about how you think about what is clearly a -- it looks like it's going to be an enormous resource base. When you were doing the southern joint venture, I think one of the considerations was the need to hold acreage, I'm guessing you don't have that problem in the core of your Spraberry area. So I'm just thinking about, how are you thinking about this thing longer term? Is this something that would ultimately make a joint venture, but would that make sense? Or given the step-up in rig count you're planning, is this something you intend to do organically? I will leave it there.

Yes, if you recall what drove us to the south, in fact, Chris and Tom -- Tom Spalding and Chris Cheatwood always told me that we should be drilling to the north because this is the best acreage. The only reason we went to the south was because we did have 50,000 acres that was expiring. We've actually -- have renewed that and got a three-year extension, but we do have a continuous development clause on that, also, to the south.

Also, Tim and I have both mentioned, we do have the 15 vertical rigs to the north that are protecting leasehold on continuous development clauses. We're really protecting --- they're great economics on vertical, but we're really protecting them also for future horizontal Wolfcamp and Shales over time. Right now, obviously, we're doing the recent deal to the south.

We feel like that we don't need to do a JV at this point in time. It's always an option down the road. For the north, obviously, the north is going to be worth a lot more than [$]21,000 per acre, based on our results so far, but we have no contemplations at this point in time. It is an option we have way down the road, and would considerate at some point in time.

All right. I will let someone else jump on. Thanks, guys.

Michael Hall with Robert W. Baird.

Congratulations on all the progress.

Thanks, Michael.

I just wanted to follow up a little bit on your commentary on plans around the Spraberry Shales. First, just putting those perhaps in the context of potential implications for the resource base, and then also timing of those first tests, how we ought to think about that?

Yes, on the resource slide, we did not include the Lower, or the Middle Spraberry Shales, as outlined on the log that Tim went over. We only include a risked Jo Mill in the resource potential, so at this point in time, with no production history, we do have core analysis and log data that shows there's a huge amount of oil in place in both of those intervals. We do expect a little bit lower reservoir pressure.

So that really, the critical thing is getting good rates out of those, so that's why they are not in our -- really our production forecast, or our reserve potential in that regard. Jo Mill, we did use about a 500,000-barrel type curve, but we heavily risked it in that regard into our resource potential. Tim, you want to comment on the drilling plans and the (multiple speakers) in the Spraberry Shales?

Yes, I think as I said, we're going to look at a combination of wells in the Spraberry Shales and the Jo Mill over the next couple of years. That schedule is actually being still worked out, and the definition of it is not at the point we can disclose the exact number of wells and what zone for what timing. But suffice it to say, about 15% to 20% of our wells -- 15 to 20 wells will be drilled in those three zones. I wouldn't be surprised if we try to do a mixture of all three in this year, and then further increasing that in 2014.

Okay, makes sense. Just to clarify, with the success in the horizontal development of the Spraberry Shales, would that eat into the vertical Spraberry resource, or would you view that as additive?

Yes, the -- we will -- what has happened, you saw where we had to move off 80 million barrels on our press release on our reserves from reaching the five years of issue with the SEC. We still have some more of those over time, as we move to more horizontal drilling. Eventually, at some point in time, if we have tremendous success in all three Spraberry zones, it will point to less and less vertical drilling, but the vertical drilling is important, again, to hold leases by production.

So, over time, you will see a lot more horizontal Wolfcamp being booked, and also Spraberry Shale intervals, horizontal being booked and less vertical. So, I don't think we'll ever give up on the vertical, because we need to hold leases. We're also adding other zones to the vertical, such as the Strawn, the Atoka, and the Mississippian, to make it even more economical. So it will probably happen slowly, Michael. We did move from 40 to 15 vertical rigs, but we really envision a 15-vertical rig program over the next three years.

Charles Meade with Johnson Rice.

Two questions for you, and one is, actually, probably the first one is a good follow-up to that. At one point, you guys were talking about a development pattern for a 960-acre unit that, I believe, has 14 horizontals in the Wolfcamp, and then an incremental, I think, 40 or 42 vertical wells. Should we just assume that that model is not applicable going forward? Or is that still something that you guys are contemplating?

Charles, this is Tim. I think what's happened, of course, is as we have gotten more information from drilling and particularly different zones, we're really looking at a situation you could have multi-stack laterals, and downspace from even the 140-acre spacing, perhaps as low as, let's say, 70-acre spacing. But you could have literally up to six stacked laterals in some of these areas.

So that's going to take a substantial amount of capital. It's possible that you could be pushing out vertical drilling sometime into the future rather than necessarily focusing on a combination of horizontal and drilling -- horizontal and vertical drilling over that 960. So I think that is still under evaluation. I think right now we're getting pretty excited though about all of these additional horizontal zones.

Got it. And then following up on that, one of the horizontal zones that seems to be conspicuous in its absence of mention is the Wolfcamp C. Is that more -- is that permanently off the map for you guys? Or is it just your sense that that is at the back of the line and you're holding depths with the Wolfcamp D? Where does it fall on that spectrum?

I think where it is, it is certainly not something we're ready to condemn. In fact, some of our acreage looks prospective for the Wolfcamp C. However, it is not all of the acreage. It comes and goes as to prospectivity. So it is just down the seriatim of opportunities to the point where it's -- we're not going to get to it before we get the rest of this stuff done.

It is just at the back of the line. Okay, great, guys. Thanks much for the color.

Brian Singer with Goldman Sachs.

I wanted to follow up on the timing it takes to bring wells on-line, the horizontal wells in the Wolfcamp on-line. I think you mentioned it is more like 120 days. Can you just run through the key bottlenecks there and how you see that playing out in terms of your ability to reduce that over the course of the year?

Well, the first thing to be said is the drilling of the wells, we're actually working hard to reduce the number of days drilling, but in general, the early drilling of the horizontal wells is roughly around 30 to 40 days. Some of the wells, in fact, the last 10,000-foot lateral we were mentioning in the earlier comments, we drilled in as few as 18 to 19 days. So that is one area we are going to be looking at reducing, basically, time on the wells in terms of drilling.

The second thing is, to the extent we have a frac bank, or a lot of days in between when the well is drilled and then prepare it for fracking, the fracs themselves take only about 8 to 10 days, in terms of total time, in terms of the number of stages pumped. But then we have time where we're waiting on basically connecting the wells, and the infrastructure in a lot of these areas is being built out to the areas. So in a lot of these areas, we're in a situation in which we're drilling the first large volume wells. A lot of cases we're drilling pad -- we're doing pad drilling.

So to the extent we're doing pad drilling, we're drilling, say, three wells on a pad, each of those takes 30 days, you're in a situation where you start getting -- you're not going to be producing the other wells on the pad until they're all drilled. So when you start looking at it on average, the averages of all of those components, our average is 120 days. It will be our objective to move that down as we move forward. Pad drilling works against that, as I mentioned. But nonetheless, it will be our objective to continually monitor this and try to improve it through time.

Great. Thanks. That's helpful. And then separately, on the use of longer laterals, you may have said this, but could you just refresh us on the increase in well costs to get to the 7,800 and then again to the 10,000, to, I think it's half [the amount] to $2 million? But then more importantly, what would you expect out of the EUR? We certainly see some strong initial rates, but what's your expectation? Are you playing for an increase in -- or a decrease in funding and development costs? Or are you just playing for a proportional increase in EUR?

Well, I think if you look at our empirical data on this, of course, it is relatively limited in the fact that we've only got one 10,000-foot well currently producing even though we've drilled a couple more and waiting on production. But the data shows that the -- going from about 7,000 to 7,500 feet in terms of lateral length to 10,000 is about $1.5 million incremental costs.

For that, at least as to this data point we're looking at now, you look at about a 40% increase in productivity. So your well cost is going up probably 20%, but your productivity is going up 40%. So therein lies a lot of capital efficiency. I think what you're going to see is, as you alluded to, when you're adding essentially more volume at less cost, you're going to reduce your F&D costs on each well and therefore, in the entire program.

So implicit in that, is your expectation that the decline rate will stay the same for the longer lateral well, or will we -- do we see a different decline curve?

Actually, if you take a look at our data, it looks very similar. This is true of the Hutt area, it is true of the Giddings area, it is true of the 10,000-foot lateral. They tend to look very close in terms of the actual shape of the decline curves. What we're really alluding to is the fact that these longer laterals start at a higher level and stay at a higher, level but still decline at a similar rate.

Brian Corales with Howard Weil.

Maybe just a follow-up question there. So basically, the 575,000-barrel or 650,000-barrel type curve, that is based more on a 5,000-foot lateral?

No, that is based on a 7,000-foot lateral.

7,000-foot lateral. Okay. Tim, you mentioned testing (multiple speakers).

Let me correct that real quick, because when we're talking about the Giddings wells, we're comparing those to a 650,000 BOE, unadjusted for length, and the lateral length of those were 5,300. When we talk about the southern Wolfcamp area, we use 575,000 BOE as the average EUR for a 7,000-foot lateral equivalent. So, you have a little bit of apples and oranges, you have to understand there.

No, no, no, understood. Okay. Thank you. And then Tim, you talked about tighter spacing, are you all currently testing downspacing from 140s, or is that way down the road?

I think we will be doing some of it in 2013. This year's drilling we will be testing that idea. That will be a limited handful of wells. But we need to start that process to understand for longer term planning, what the eventual spacing situation is, and that starts this year.

Is it -- do you think that varies by Wolfcamp zone?

Probably not Wolfcamp zones. I think the question is, as you get into zones where they had much more drilling such as the Spraberry Shales and the Jo Mill; you may be more limited on down spacing, but I don't think that's going to be the case in the Wolfcamp.

Okay. And then one final, if I could. You're averaging longer laterals now in the Eagle Ford. Should we just assume that we will see increased EUR over -- whether it's this year or next year, over time?

Yes, I think we still see a similar relationship, that is basically linear, a linear relationship, as we do in the Permian Basin, between lateral length and productivity. That said, the actual incremental cost is not linear. It is not that much more expensive as we've shown to drill out of, let's say, 1,000 feet more than not. So this is where your capital efficiency increases.

Leo Mariani with RBC Capital Markets.

I was hoping maybe you could take us through what you are seeing on oil cuts for some of your longer-producing wells horizontally in the Permian. Obviously, a lot of these wells when they come on, somewhere around 75%, 80% oil. Can you just talk about how maybe that cut degrades a little bit over time and what your expectations are for a longer-term tail oil cut in a lot of those wells?

Yes, we can already see this, Brian. It is as expected. Your GOR, generally when these wells are brought on production, is about 1,000. If the case, and this is true of all vertical wells in addition to horizontal wells, we see that the GOR goes up through time, and actually, it goes up to 2,000 and 2,500 eventually. We already see this in some of the horizontal wells. They tend to come on about 80% to 90% oil, and then they gradually, through time, even over the first year or so, get down to 75% oil. It's just a factor of drawing down the pressure in the reservoir.

Okay. That's helpful. Just a question on your three-year guidance, where you're talking about 13% to 18% production growth. Obviously, there's a lot of factors going into this, but is -- would you guys say that the biggest factor is the oil price range when you guys talk about $85 to $100 WTI moving around in that guidance?

Your two big factors is $85 flat to $100 flat on WTI, and the second factor is that in the northern program of the Wolfcamp and Spraberry Shales, we only use roughly a 500,000 barrels type curve.

Okay, that's helpful. Last question here on Alaska, obviously, you guys have a pretty nice drilling program. Because if that's successful, do we expect production to start ramping up in the second quarter potentially of '13, or will we have to wait for additional infrastructure at some point later on?

Well, first of all, the southern Nuna wells will not be able to count towards production because we don't have a sanctioned project so that's not going to be on the table. However, to the extent that our projects that are related to the fracking from the island work as they did last year, you should see a pretty significant increase in production and it would start basically in the second quarter.

There are no facility limitations in terms of putting those wells on production from the island. So, we would just turn them on to sales. We're hopeful that we can get the kind of results that we did last year when we put that N1 Nuiqsut well on it at 5,600 barrels a day. So, we could have a pretty material bump in production, if all goes well.

We have time for one more question. Arun Jayaram with Credit Suisse.

Scott, good seeing you last week. I did want to ask you a little bit about -- obviously, some good well results, very good well result up north, and a successful extended lateral on the south. Just comment to the extent that you believe you've derisked the horizontal Wolfcamp in terms of acreage or location. We had been thinking about maybe 200,000-acre potential up north, but looking from the slide you're looking at, maybe a broader swath closer to 600,000 acres. Just wanted to get your comments on derisking the play thus far.

Yes, Arun, as we have stated, we have thousands of wells that we've drilled, hundreds of wells, we've taken core data and extensive open hole logging data from both us and other operators. We're the largest holder of that data in the Midland Basin. So for the last 18 months, the geologist team have wanted to drill a lot more wells up north because we know it's probably the best area. What drove us down south was essentially the expiring acreage on the University.

So, I think the Diamondback well confirms, because it came in at half the lateral length as the HUD and it came in at about half the rate. So to me, that's an important well, it is about 10, 12 miles away, further out west. That confirms the maps. So the Martin County well, to the north, will be the next set of wells. So we're very confident that it will continue to play out like we have shown.

Okay. In terms of the Martin County, I just wanted to get your quick take. I think W&T Offshore had a pretty good well result on a shorter lateral. Presumably, this increases your confidence around your two Martin County tests.

Yes, I have not -- I've asked my geo team about that. I have not gotten confirmation on what zone they penetrated, so I do not know. But I saw that they potentialed the well with the Texas Railroad Commission.

Okay. Thanks a lot, guys.

Thank you. And again, that is the last. We're are going to have to get off. We appreciate it. We will be traveling around over the -- several of the conferences over the next three weeks and we're looking forward to meeting with everybody. Again, thank you very much.

Thank you very much. That does conclude our conference for today. I would like to thank everyone for your participation. You may now disconnect.