Pioneer Natural Resources Management Discusses Q4 2012 Results - Earnings Call Transcript

| About: Pioneer Natural (PXD)

Pioneer Natural Resources (NYSE:PXD)

Q4 2012 Earnings Call

February 14, 2013 10:00 am ET


Frank E. Hopkins - Senior Vice President of Investor Relations

Scott D. Sheffield - Chairman and Chief Executive Officer

Timothy L. Dove - President and Chief Operating Officer

Richard P. Dealy - Chief Financial Officer and Executive Vice President


Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Arun Jayaram - Crédit Suisse AG, Research Division


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 Again, the Internet site to access the slides related to today's call is 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 the 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.

Frank E. Hopkins

Good day, everyone, and 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 a.m. 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 are 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'll open up the call for your questions.

So with that, I'll turn the call over to Scott.

Scott D. Sheffield

Thanks, Frank. Good morning. I'll start off on the financial and operating highlights on Slide #3. The fourth quarter, we had adjusted income of about $107 million or $0.83 per adjusted share.

Production, including the Barnett by bringing them 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's up 29% for the year versus '11, which is at 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 funding cost 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 of 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 is $600 million in 2014.

Long term -- 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 midyear 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 $85 flat price deck for WTI for the next 3 years up to $100 WTI flat for the next 3 years, we're targeting a 13% to 18% compounded annual growth rate from '13 to '15, and we'll go over more the backup for that when we get to the growth slide.

Slide #4, drilling highlights. Really, we feel like this is probably the most important quarter in the company's history for a couple items: One, we have brought on what we feel like matches our deal size maps, the best well in the horizontal Wolfcamp Shale play in the B interval in Midland County. That's essentially 1,700 barrels of equivalent per day and 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 2 wells in the south in the Giddings horizontal Wolfcamp Shale wells, which we'll 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. And we announced a $1.74 billion transaction with Sinochem, and that transaction is expected to close in the second quarter of 2013. In addition, we had tremendous results in our JV area with -- 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 a little bit over 1,000, 80% oil. Also, if you recall, we've been showing you in our maps the last couple of quarters that the B interval is ticking up into the 500, 600-foot range that we're start -- we feel like that's going to take 2 wells to drill up the B interval. We drilled our first Lower B interval well, it came on; it's currently producing way above the 575,000 barrel type curve. And 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 billion or greater than 8 billion barrels of oil equivalent per day. And we'll comment on that as we get to the slide and talk about the backup 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'll 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 have $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 solar disposal wells, additional gas processing plants and automation.

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'll be running 2 rigs over the next 3 years with $185 million, with continued significant growth over the next 3 years.

The $240 million of other capital, as we have mentioned over the past several quarters, obviously, a big decrease in vertical integration. We're 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 buildings, field offices and others. That's again primarily mostly going to be pumping services, office, new offices and also field offices. And about $52 million of that is in a Midland building for our employees out in the north side of Midland.

Turning to Slide 6, and going over our growth rates and what makes up those growth rates. Again, we're targeting 13% to 18% compounded annual growth rate for the next 3 years. That's in the range of $85 oil flat for WTI to $100 oil flat for the next 3 years. Again, we do have the sale to Sinochem, a little bit over 400,000 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 HUD type curve, which the well came in 1,700 barrels a day. We are modeling in this growth profile essentially a 500,000 to 575,000 barrel type curve. So we are very, very conservative in regard to not using the HUD 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 #7. Again, we've outlined 3 critical items in this type curve. We have 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 2 best wells in the northern part of our joint venture area to the south of 207,000 acres. The 2 wells, if you notice, they now have been put on our official lift, 1 pumping in at 1 gas lift. They're pouring -- they're starting to perform above the type curve, so above the 650 type curve. Those laterals were 5,300. 2013 drilling, we will focus a lot more wells in this area.

In addition, the HUD well to the north, it came on 1,700 barrels a day equivalent, averaged 1,500 barrels a day equivalent. That's essentially twice as much as the Giddings wells, so we obviously haven't put on a type curve. But obviously, it implies a significant increase way in above the Giddings for this HUD well. It also confirms our maps that our geoscientists have built over last 2 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 2 wells in northern Upton County. We announced them last quarter. An update on those, we normalized this. If you recall, they were drilled 2,500-foot laterals. We normalized it to 5,000-foot laterals, is what we expect to drill on our appraisal program to the north over the next 2 years. More of our wells are going to be in the 5,000-foot range in the Jo Mill and also in the Spraberry shales. But you can see, both of these wells are performing way above the 650 type curve. And 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 in Wolfcamp. So again, we're very excited about this.

Going to Slide #9. This is one of our treasure maps that the geoscience team has built over the last 2 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 of data points. So we have a lot more data points than just having 2 wells in Midland County. We do have the well located in the middle of Midland County, about 25 wells -- 25 miles north of the Giddings wells. In addition, we point out a third-party well that IP-ed at 890 barrels a day, not too far from our HUD wells on the western -- northwestern side of the Midland County with 3,700-foot lateral length.

We do have 2 wells up in Martin County. But you can look at the vast amount of acreages 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's important to note that Tier 2, several wells have been drilled by us and other operators in Tier 2, and also expect it to be very productive and economic.

And finally, on Slide #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'll 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. And so our southern area obviously went down with that sell. 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 2 Spraberry shales, both the middle and the lower Spraberry shales, and we're also not including any downspacing. All this is calculated on 140-acre spacing. We are drilling our Eagle Ford and our Barnett down to 70-acre spacing now, so we've got 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.

Timothy L. Dove

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.

And first, I'm going to focus on the southern Wolfcamp joint interest area. It's, 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 was the first of the lower B wells, also the 10,000-foot lateral well he mentioned. That well has really been phenomenal. It's made 31,000 barrels in its first 34 days of production, so it's a phenomenal well. And then, of course, our first 6 -- one of our A wells is being very successful in that area as well. So the drilling campaign is doing exceptionally well, with 7 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 -- that's a part of the agreed-to work plan and budget for Sinochem.

The 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 of these wells for an average 7,800-foot lateral. Of course, that will 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's $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 essentially a 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 -- or, used for some time and that is slickwater fracs. We have 1 well on flowback that we've used slickwater and 1 that is yet to be completed. But suffice it to say, there's substantial savings for slickwater fracs as compared to shale-conveyed fracs that can range from $800,000 to $1 million per well, which means you 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 costs continuing, probably about $20 million this year. And of course, that's for microseismic cores, log sleets and so on.

As you look forward to 2014 and beyond, we'll 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. And as Scott has already alluded to, the work will be done to evaluate how far we can downspace this field, in which case we're just adding significant opportunities. So the objective is 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 1 rig running. Of course, the plan is to increase that to 4 rigs early in 2013's second quarter. And we have drilled our first 2 horizontal Wolfcamp shales in Midland County, and these are the ones Scott referred to as being about 25 miles north of the successful Giddings horizontal wells. This well has been -- this HUD well has been absolutely phenomenal. It's a B zone well. It's made 40,000 barrels in its first month of production.

Similarly, as you look at the crude [ph] 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, 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 where -- it's in the frac bank waiting to be frac-ed.

We now are, as Scott mentioned, drilling a couple wells in Martin County. Those are Wolfcamp B wells, and we'll 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 have drilled 7,000 wells out here, and we've done substantial petrophysical analysis on some 900 wells that 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'll talk more about that on the next slide, Slide 13. As shown here, we'll be targeting in our 2013 drilling plan about 30 to 40 wells in the north. About half of those, 15 to 20 wells, will target the various Wolfcamp zones, A, B and D. In addition to which, we'll drill a similar number of wells, something like 15 to 20 wells, to test the Jo Mill, which has already been the subject of 2 wells, as well as the -- 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've averaged about 37,000 BOE, having only been on production for about 4 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 drill cost for 7,000-plus foot laterals. Recall, as we go -- we are deeper drilling as we go north.

It's 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's 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.

And as shown on Slide 14, it's really, in our case, about connecting the dots. You can see here kind of a broad map of where we plan to appraise the various areas of our acreage, including in Martin County and Midland County, Giddings 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. And what we're, of course, chasing is these 6 intervals, including the 3 Wolfcamp intervals, 1 Jo Mill and 2 Spraberry shales that I showed on the earlier slide.

And if you consider that across these stacked laterals, you have about 600,000 acres of planned view, that means we're really dealing with something that's 3 million gross acres when you consider it in 3D perspective, due to the stacked intervals. And we believe from the information we've already divined from all the science work I 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'll exit 2013 with about 5,000 to 7,000 BOE net of horizontal production. Of course, our production is backloaded in 2013 simply because we're just in the process of ramping the rigs up, and 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 were more like 70 days, so that has the effect of skewing production through the back end of the year. We do, however believe and continue to believe that horizontal drilling is more capital efficient than vertical drilling, and so that's why we're heading with more capital towards the horizontal campaign.

And where we're going to be 4 rigs this year, we plan to be about 6 to 8 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's already been proven, there's substantial opportunity in the Atoka for horizontal drilling. That's been proven in Martin County by other operators. But we'll 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 Mississippian.

So suffice it to say, what we're 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's 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, and we will be continuing our vertical program albeit at a smaller rig count. We'll be drilling with only about 15 rigs this year, 2013, drilling about 300 wells. Scott already mentioned the fact that the reason we were landing on 15 rigs is that we have continuous drilling obligations on many of our leases. And by drilling wells vertically, we've not only preserved the leasehold, but we've also preserved 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 -- we're expecting, at least, to draw down our frac bank. We did build somewhat of a frac bank at the end of 2012. I'll 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 the activity I've mentioned in both 2012 and 2013, where we expect over many years that the production will grow substantially in 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. And 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'll be growing these assets 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 anticipate it's going to be 11,000 to 14,000 barrels a day this year. And 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, 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'll 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 proppant, replacing ceramic sand and anticipate the program will be over 50% white sand this year. And of course, there's a dramatic cost savings related to frac-ing 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'll 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 cost per well probably in the neighborhood of $500,000, but the data shows it's well worth it. The returns on the extra 500 feet are very strong.

Still looking at $7 million to $8 million well cost, 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'll add 1 more by the end of 2013 and perhaps 1 in 2014. But essentially, our infrastructure build-out is nearing completion in the Eagle Ford.

This asset really continues to deliver, and you can see that on Slide 18. 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. And 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 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 consider to be the PDP value, and we got very really 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, and we'll 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 1-rig count, where we currently are, to a 2-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% pretax returns. So this drilling does make sense for us. And the objective is to retain our best acreage, that it to say, the acreage with the most liquid-rich opportunities. And 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. We've seen several wells drilled substantially below $3 million. In fact, some of these wells have been drilled in 7 and 8 days. So we really believe that this Barnett Shale asset, as we drill it out, is really going to add value. And as you can see, 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 our activities that we have underway, the first of which relates to the frac-ed program. If you 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. It made 5,600 barrels a day. That well is still making 2,000 barrels a day on a flat line, and so it's been a tremendously strong well. And accordingly, we're planning to frac 4 more wells, one of which is in the Torok formation and 3 in the Nuiqsut. We're currently mobilizing the equipment out on the ice, and the first fraction commence in the next couple of weeks. And we anticipate finishing that program for -- 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 2,000 barrels with facility constraints. We're still somewhat facility-limited with that well. It was testing right on 2,800 barrels a day, so it looks very, very strong. At the same time, we're drilling an offset well as the Nuna 2 well to this first well, and it will also be frac-ed. 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.

And with that, I'll pass it over to Rich for a discussion of the fourth quarter financials and his outlook for the first quarter.

Richard P. Dealy

Thanks, Tim. I'm going to start on Slide 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 noncash impairment charge related to our Barnett Shale assets that we moved back into continuing operations. So adjusted for those items, we were 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 be in an apples-to-apples comparison. You can see there that, basically, we're within on the positive side guidance with the exception of G&A, which includes performance-related compensation that we reported in the fourth quarter. All the other items were in middle of the guidance or on the good side.

Turning to Slide 22, price realizations. Now looking at the green bars, you can see that oil was down 5% in the fourth quarter from the third quarter, just under $84. NGLs continue to be fairly flat, running still 35% to 40% of WTI oil prices. And 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 anymore going forward. And 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 were 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 of 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 cost down further.

Turning to Slide 24. First quarter production guidance of 165,000 to 170,000 barrel oil equivalents per day, and 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 are all consistent with the fourth quarter. So I won't go through those individually, but they're there for your review.

So Vickie, I think at this time, we'll go ahead and open up the call for questions.

Question-and-Answer Session


[Operator Instructions] And we'll take the first question today from Doug Leggate with Bank of America Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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 2 in terms of what is prospective for all 4 Wolfcamp zones? And it's probably a little too early, but is there any specific differences you could share between your expected EURs from the wells? And I'm guessing it's a little early for that. But I've got a follow-up, please.

Scott D. Sheffield

Yes, obviously, the Wolfcamp B is the focus. We haven't put a type curve on the 1,700 barrel a day well, the HUD well. But it looks like it's 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 a huge potential. But right now, we just don't know the upside in regard to the A. We have -- the offset well to the HUD well is a Wolfcamp A. We expect to frac it in the next few weeks, so we should have information over the next 2 or 3 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, and 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's not as rich organically on the eastern side of the play, and 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'll eventually move to the A and then eventually move to the Cline in the northern appraisal program.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

My follow-up is really, I guess, more strategic about how you think about what is clearly -- it looks like it's going to be an enormous resource space. When you -- within 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 do think about this thing longer term? Is this something that would ultimately make a joint venture? Would that make sense? Or given the step-up in rig count that you're planning, is this something you intend to do organically? And I'll leave it there.

Scott D. Sheffield

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 it's the best acreage. The only reason we went south was because we did have 50,000 acres that was expiring. We actually have renewed that and got a 3-year extension, but we do have a continuous development clause on that also to the south. Also, Tim and I had both mentioned, we do have the 15 vertical rigs to the north that are protecting leasehold on continuous development clauses. We're really protecting our grid 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. That'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's an option we have way down the road and would consider at some point in time.


And we'll now go to Michael Hall with Robert W. Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

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

Scott D. Sheffield

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 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 of those. So that's why they are not in our -- really, our production forecast, or our reserve potential in that regard. On 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 in the next few years in the Spraberry shales?

Timothy L. Dove

See, I think, as I said, we're going to -- you're looking at a combination of wells in the Spraberry shales and the Jo Mill over the next couple of years. That schedule is actually still being worked out, and the definition of it is not what we can disclose, the exact number of wells, in what zone, for what timing. But suffice it to say, about 15% to 20% of our well -- or, 15 to 20 wells will be drilled in those 3 zones. I wouldn't be surprised if we tried to do kind of a mixture of all 3 in this year and then further increasing that in 2014.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay, makes sense. And just to clarify, with success in the horizontal development of the Spraberry shales, would that ease into the vertical Spraberry resource? Or would you view that as additive?

Scott D. Sheffield

Yes, the -- we will -- what's happened, you saw where we had to move off 80 million barrels on our press release on the reserves from reaching the 5 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, we have tremendous success in all 3 Spraberry zones, it will point to less and less vertical drilling. But the vertical drilling is important again to hold leases by production. And 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 that 15 vertical rig program over the next 3 years.


Next is Charles Meade with Johnson Rice.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

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 kind of assume that, that model is not applicable going forward? Or is that still something that you guys are contemplating?

Timothy L. Dove

Charles, it's Tim. I think what's happened, of course, is as we've gotten more information from drilling in particular different zones, we're really looking at a situation you could have multi-stacked laterals and downspace from even 140-acre spacing, perhaps as low as, let's say, 70-acre spacing. But you can have literally up to 6-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 -- with that still under evaluation, I think right now, we're getting pretty excited about all these additional horizontal zones.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

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 that just your sense that, that's at the back of the line and you're holding depths with the Wolfcamp D? I mean, where does it fall on that spectrum?

Timothy L. Dove

I think where it is, it's certainly not something we're ready to condemn. In fact, some of our acreage looks prospective for the Wolfcamp C. However, it's not all of the acreage. It comes and goes as to prospectivity. And so it's 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.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

It's just at the back of line. Okay, great.

Timothy L. Dove



We'll now go to Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

I wanted to follow up on the timing it takes to bring wells online, the horizontal wells and Wolfcamp online. I think you mentioned it's 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?

Timothy L. Dove

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 earlier comments, we drilled in as few as 18 to 19 days. So that's one area we're 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, there a lot of days in between when the wells are drilled and then prepared for frac-ing. The fracs themselves take only about 8 to 10 days in terms of total time, in terms of the number of stages pumped. Then we have time when we're waiting on basically connecting the wells, and then infrastructure in a lot of these areas is being built out to the area. 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 and we're doing pad drilling. So to the extent we're doing pad drilling, we're drilling, say, 3 wells on a pad, each of those takes 30 days. You're in a situation where you start -- 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 those components, our average is 120 days. And it will be our objective to move that down as we move forward. Pad drilling kind of works against that, as I mentioned. But nonetheless, it will be our objective to continually monitor this and try to improve it through time.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great, that's helpful. And 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? I think it's kind of have to 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 planning for an increase in -- or a decrease in funding and development costs? Or are you just planning for proportional increase in EUR?

Timothy L. Dove

Well, I think, if you look at empirical data on this -- of course, it's relatively limited. And the fact, 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 cost. And for that, at least as to this data point we're looking at now, you could be looking at about a 40% increase in productivity. And so your well cost is going up probably 20%, but your productivity is going up 40%. So therein lies a lot of capital efficiency. And I think what you're going to see is, kind of as you alluded to, I mean when you're adding essentially more volume at less cost, you're going to reduce your F&D cost on each well and, therefore, in the entire program.

Brian Singer - Goldman Sachs Group Inc., Research Division

So I guess implicit in that, is your expectation that the decline rate will stay the same for the longer lateral well? Or would we see a different decline curve?

Timothy L. Dove

Actually, if you take look at our data, it looks very similar. This is true of the HUD area. It's true of the Giddings area. It's 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 that fact that these longer laterals start at a higher level and stay at a higher level but still decline at a similar rate.


Next is Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

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

Timothy L. Dove

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

Brian M. Corales - Howard Weil Incorporated, Research Division

7,000-foot lateral. Okay, okay. And Tim, you mentioned testing...

Timothy L. Dove

Let me clarify 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 feet. 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 we have a little bit of apples and oranges you have to understand there.

Brian M. Corales - Howard Weil Incorporated, Research Division

No, no, no. Understood. Okay. And then Tim, you talked about tighter spacing. Are you all currently testing downspacing from 140s? Or is that kind of way down the road?

Timothy L. Dove

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

Brian M. Corales - Howard Weil Incorporated, Research Division

And is it -- do you think that varies by Wolfcamp zone?

Timothy L. Dove

Probably not Wolfcamp zones. I think the question is, when you get into the zones where we have much more drilling, such as the Spraberry shales and the Jo Mill, you may be more limited on downspacing. But I don't think that's going to be the case in the Wolfcamp.

Brian M. Corales - Howard Weil Incorporated, Research Division

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 an increase to EUR over -- whether it's this year or next year over time?

Timothy L. Dove

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


We'll now go to Leo Mariani with RBC Capital Markets.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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

Timothy L. Dove

Yes, we can already see this, Brian (sic) [Leo]. It's kind of as expected. Your GOR, generally when these wells are brought on productions, it's about 1,000. And if the case -- and this is true of all vertical wells in addition to horizontal wells, we see that the -- the GOR goes up through time. And actually, it goes up to 2,000 and 2,500 feet -- 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 though we're in the first year or so, get down to 75% oil. It's just a factor of drawing down the pressure in the reservoir.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, that's helpful. And I guess just a question on your 3-year guidance where you're talking about 13% to 18% production growth. Obviously, there's a lot of factors going into this, but is -- when 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?

Scott D. Sheffield

Your 2 big factors is $85 flat to $100 flat on WTI. And the second factor is in the northern program, the Wolfcamp and the Spraberry shales, we only use roughly a 500,000 barrel type curve.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, that's helpful. And I guess last question here on Alaska. Obviously, you guys have a pretty nice drilling program. To the extent that that's successful, do we expect production to start ramping up in the second quarter potentially in '13? Or will we have to wait for additional infrastructure at some point later on?

Timothy L. Dove

Well, first of all, the southern Nuna wells, we'll 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 frac-ing 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 at 5,600 barrels a day. So we could have a pretty material bump in production if all goes well.


And we have time for one more question, and we'll take that question from Arun Jayaram with Credit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

I did want to ask you a little bit about -- obviously some good well results; a very good well result up north and a successful extended lateral on the south. And just comment to the extent that you believe you de-risked the horizontal Wolf count terms of acreage or locations? I guess, we have 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 de-risking the play thus far.

Scott D. Sheffield

Yes. Arun, as we have stated, we have thousands of wells that we drilled, hundreds of wells we've taken core data and extensive open note logging data from both us and other operators. We're the largest holder of that data in the Midland Basin. And so for the last 18 months, the geologist team had wanted to drill a lot more wells up north because we know it's probably the best area. And 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, it came in about half the rate. So to me, that's an important well. That's 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.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And 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 the shorter lateral. Presumably, this increases your confidence just around your 2 Martin County tests.

Scott D. Sheffield

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

Thank you. And again, that's the last. We're going to have to get off. We appreciate it. And we'll be traveling around over to several of the conferences over the next 3 weeks, and we're looking forward to meeting with everybody. Again, thank you very much.


And thank you very much. That does conclude our conference for today. I'd like to thank everyone for your participation, and you may now disconnect.

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