Diamondback Energy Inc (FANG) 2012 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy fourth quarter earnings conference call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at this time.

(Operator Instructions)

As a reminder, this conference call is being recorded. I would now like to turn the conference over to your host, Mr. Jeffrey Goldberger. Mr Jeffrey Goldberger, you may begin.

Thank you, Mimi, and good morning and welcome, everyone, to Diamondback Energy's fourth quarter and full year 2012 earnings conference call. Again my name if Jeffrey Goldberger and I am with KCSA Strategic Communications, Investor Relations counsel to Diamondback. Representing the Company are Travis Stice, Chief Executive Officer; Tracy Dick, Chief Financial Officer; Russell Pantermuehl, Vice President of Reservoir Engineering. We hope you had an opportunity to review the release we issued at the close of business yesterday.

Let me quickly outline the agenda for today's call. Travis will begin with a brief introduction to Diamondback and a quick overview of our operating results. Tracy will then bring you through the financial details, including an income statement and balance sheet, along with key operational metrics for the three and 12 months ended 12/31/12. Finally, Tracy will provide full year 2013 guidance and then open up the call to questions.

As a reminder, some of the matters we will discuss on today's call are forward looking statements within the meaning of the federal securities laws. All statements other than historical facts that address activities that Diamondback Energy assumes, plans, expects, believes, intends, or anticipates and other similar expressions will, should or may occur in forward looking statements are forward looking statements. The forward looking statements are based on management's current belief based on currently available information as to the outcome and timing of future events. These forward looking statements involve certain risks and uncertainties that could cause results to differ materially from those expected by the management of Diamondback. Diamondback Energy undertake no obligation to update or revise any forward looking statement.

During our call today we will reference certain non-GAAP financial measures, which we believe provide useful information for investors. We include reconciliation of those measures where appropriate to GAAP. Diamondback Energy assumes no obligation to update the information presented on this conference call.

This call is the property of Diamondback Energy, Inc. Any distribution, transmission, broadcast, or rebroadcast of this call in any form without the express written consent of the Company is prohibited. A replay of the call will be available from today at the 1.00 PM eastern time through Tuesday, March 5, 2013 at 11.59 PM eastern time. To access the replay, call 855-859-2056 in the US and Canada or 404-537-3406 for international callers and enter the confirmation code 12520719. The webcast will also be archived on the Company website for 30 days. Now my pleasure to turn the call over to Travis Stice.

Thank you, Jeffrey. Welcome, everyone, and thank you all for listening to Diamondback Energy's fourth quarter and year-end 2012 conference call. The last 18 months has been a whirlwind of activity for Diamondback Energy, culminating with the successful completion of our IPO on October 17 of 2012. Since this is our first earnings conference call, I want to take the opportunity to provide a detailed overview of Diamondback Energy. But before doing so, I'd like to just take a moment to describe our leadership team and some of our guiding principles.

When I joined Diamondback in April of 2011, I had the opportunity to assemble an operating team with an established track record of delivering superior results. Each of the members of our senior leadership team is at the top of his or her game and brings to Diamondback almost 30 years of operating experience per person. Although this team is relatively new to Diamondback, with the exception of our CFO, Tracy Dick, who's been with Diamondback since its inception, most of us had worked together at the likes of Burlington Resources, Conoco Phillips, Laredo Petroleum, which I believe will prove to be an important ingredient to operating success. With our senior leadership team in place, we worked to articulate the guiding principles we've established as creating successful strategies from our collective prior experiences. Not only to insure the long-term success of Diamondback, but also to hold leadership accountable to our employees and our investors. These guiding principles are grounded in the following concepts. Superior execution, transparency in communications, and delivering best in basin's margins.

So, turning to our underlying story, Diamondback Energy is an independent E&P that's headquartered in Midland, Texas and focused on the Permian Basin primarily within the Wolfberry Trend. Withholdings of just under 52,000 net acres at the end of 2012, Diamondback is one of a limited number of publicly traded [sheer] play operators in the Permian Basin, which allows investors to participate directly in the tremendous resurgence of drilling activity and corresponding volume growth that has taken place in the Permian Basin since 2009. In addition to developing our existing acreage, we also seek to make bolt-on land acquisitions around our existing core areas in the basin, where we believe opportunities exist to deliver high rates of return to our shareholders. Already in the first quarter of this year, we successfully acquired over 2,500 net acres in Midland County, bringing our total acreage position in the Permian to over 54,000 net acres. These additional tracks have high potential for Wolfcamp shale development and lay out nicely for long lateral development.

In terms of inventory, we have identified almost 1,900 vertical drilling locations, including 881 40-acre and 1,118 20-acre locations, as well as over 700 horizontal drilling locations. Of these 700-plus horizontal sites identified, 50% of those are located in either the Wolfcamp B or Wolfcamp A. Our acreage extends from Andrews county to Crockett County in relatively contiguous blocks, which lends itself to horizontal developments and economies of scale.

Now some specifics on the fourth quarter and full year 2012. And just as a reminder, we went public during the fourth quarter of last year, so we're really just getting this machine started. Production for the fourth quarter of 2012 on a pro forma basis totaled 4,600 Boe's per day, up 18% from the third quarter of 2012. Year-end 2012 crude reserves totaled 40.2 million Boe's and consists of 26.2 million barrels of oil, 8.3 million barrels of NGLs, and 34.6 Bcf of natural gas. During 2012 we increased our proved developed reserves by 40.6% to 12.3 million barrels or 30.7% of total proved reserves. Due primarily to pricing, we reclassified 2.6 million barrels of [pudge] to the probable reserves category. Overall, we've replaced 337% of 2012 production with reserve additions excluding revisions, which are primarily commodity price related.

Now turning to our drilling program. Not unlike many of our peers and also what we told you we were going to do during our IPO road show, Diamondback is shifting our emphasis from vertical to horizontal development. While we're not eliminating our vertical drilling activities, we plan to overweight towards horizontal drilling during 2013, with roughly two-thirds of our capital allocated to horizontal wells. Now driving this discussion, I'm sorry, driving this decision is a couple of factors. First, horizontal drilling activity is migrating north in the Midland Basin where we believe the shale is more brittle, it's deeper, and it's at higher pressure than in the southeast portion of Midland Basin where the original horizontal Wolf Camp development begin. Simply stated, we think that this portion of the Midland Basin will be better for shale development and our activity combined with industry results has essentially derisked Midland County. Out of the 25 gross horizontal wells we expect to drill in 2013, 15 of those will be in Midland county.

The other reason for migrating from vertical to horizontal drilling is economics. Not only do we think the rate of return will be higher for horizontal wells due to these high initial flow rates, the development cost we're targeting at around $15 a barrel or less is better than our typical vertical wells. Just to complete the loop on well counts, we expect to drill 37 gross vertical wells in 2013. As it pertains to our horizontal drilling program, all of our activity to date has taken place in the Wolf Camp B, which is the shale member we currently think offers the best return. However, there's at least four other shale horizons that suggest additional prospectivity that the industry is currently evaluating.

We have nine wells in various stages of development in Midland and Upton County. Results from our two earliest wells, the Kammerer 4209 H and the Janey 16 H, are promising, having been drilled to lateral lengths of 3,733 feet and 3,842 feet respectively, with each of these wells on track to achieve ERs of between 400,000 and 500,000 barrels per well. We're also encouraged by the strong results recently delivered by a Pioneer operated well, which is located within 18 miles of our acreage in Midland County. The close proximity of this activity should bode well for Diamondback's acreage and horizontal well upside.

In addition to the Kammerer and the Janey wells, we have three additional horizontal wells in Midland County and four horizontal wells in Upton County. And here's some updates on our drilling activities in Midland County. The Spanish Trail 25-1H is drilled with a lateral length of 4617 feet and is scheduled for a 19-stage frac to begin early March. The frac on this well will also be monitored using micro-seismic, which is important to us as we settle on interlateral spacing, ideal perf clustering, and gain a better understanding of frac height growth. We feel like the upside in getting this information early in our program was worth a slight delay in our completion dates.

The Spanish Trail 252-H is drilling with a target lateral length of around 4,800 feet and is also scheduled for 19-stage frac job immediately following the 251-H frac in mid-March. Finally, the serian 3812-H, which is a non-operated well in which Diamondback has 42% working interest, was drilled to a lateral length of 4,461 feet and just recently completed an 18-stage frac. The well's currently flowing back and just started cutting oil over the weekend. Our drilling activity in Upton County, where we're now drilling our fifth well, is benefiting from the continued improvements in our drilling program as measured by the reduction in days required to reach TD. We think we'll see similar improvements in reduced days for our horizontal wells in Midland County.

The Neil 8-1H was drilled to a lateral length of 7,652 feet and we completed a 32-stage frac job in late January. Flow-back operations are currently underway. And for the last seven days the well has averaged 817 barrels of oil equivalent with a peak 24-hour rate of 871 barrels a day with an 85% oil component. We're extremely excited about the early flow-back results from this well. In fact, if you look at the production that it made last night, our seven-day average now has moved actually to 840 barrels a day and that's a two stream number and that's about 87% oil. That gives you an indication of why we're still excited about that well.

Its sister well, the Neil 8-2H, was drilled to a lateral length of 6,685 feet and is scheduled for a 28-stage frac to begin within the next several weeks. The Janey 3H was drilled to a lateral length of 4,629 feet and is currently, this morning, going under -- undergoing a 19-stage frac and should begin flow-back early next week. And the last well is the well we're drilling in Upton county. Right now the Kendra 1-H. It's got a planned lateral of 7,550 feet. It look like we'll reach TD in 20 days or less.

Now there is a couple of things worth noting. First, as I mentioned, we continue to improve the efficiency of our drilling program. If you just look at the 32 days it took us to reach roughly a 3,800-foot lateral in the Janey well last year, about a year ago this time, it took us roughly 24 days to reach TD for both the Neil 8-1 and the H2H. And as I mentioned, those are both around 7,500 feet laterals. The Janey 3H, which reached TD in an amazing 13 days for 4,629-foot lateral. Not only are we drilling longer laterals, we're drilling them faster.

Simply put, in the Permian Basin, fewer days equals fewer dollars. Faster horizontal drilling will also enable us to reduce our overall spud-to-spud time to between 25 and 30 days for these 7,500-foot laterals compared to our previous expectation of approximately 35 to 40 days. Now, that's a reduction of over 35% in cycle time. Now, how that translates to cost. We believe that as we can repeat these results, development costs for horizontal wells will be at the low end of our guidance of between $7.5 million and $8.5 million for these 7, 500 foot laterals. Look for us to provide additional details on cost performance in the upcoming quarters.

Speaking of lateral link, our optimum lateral links going forward will be in that 7,500 to 8,000-foot range. We're targeting typically around an average of 30 to 35 frac stages. Moving towards these 7,500-foot laterals should result in an improved F&D cost when compared to a 4,500-foot lateral. Now, at some point we may push out to these 10,000-foot laterals, but not until at such time the industry confirms its ability to support this activity. We'll watch closely what's going on and we'll be fast followers with these two model laterals. We'll also will drill one-mile laterals where that's required by lease geometry.

Looking at our vertical drilling program, Diamondback will continue to make the most of our portfolio of multi-year, 40-acre drilling locations in order to capitalize on this opportunity. Specifically, from a high of 18 days to reach TD in the second quarter of 2011, we've been able to reduce our spud-to-TD time for our vertical wells by 36% to 11 days in the fourth quarter of 2012. Similarly, we have reduced our time until placed on production, what we call pop time, for our vertical wells from a high of 68 days in the first quarter of 2011 to 42 days in the fourth quarter of 2012. Like the cost story on horizontal wells, as we repeat this performance, costs should migrate toward the low end of our guidance for these vertical wells at $2 million to $2.2 million per well.

As noted earlier, Diamondback is dedicated to increasing our margins. To achieve this, we've allocated approximately $10 million to $15 million in 2013 to improve our infrastructure and reduce our LOE. In Midland County we're in the process of migrating water disposals from truck carriers to pipeline, which will reduce our LOE by approximately $2.50 a barrel. Similarly, we're migrating from oil haul trucks to pipeline that will improve our realizations by $1.50 to $2 a barrel. We also plan to tie together our tank batteries in Midland County to recycle 15% to 25% or more of our frac flow-back water, further reducing our disposal cost by $0.25 to $0.50 a barrel.

Last month we moved a portion of our produced water to pipe that was connected to a commercial disposal, saltwater disposal well. The monthly savings on just those volumes alone will translate to roughly a $0.50 per barrel reduction in our LOE field-wide. Combined these efforts should support our goal to reduce our direct LOE to $8.50 to $10 a barrel by the end of 2013, which excludes our indirect expenses of ad valorem and overhead of between $2.50 and $3 a barrel. We continue to look for ways to drive additional LOE reductions and as we work towards achieving these best in basins operations.

Moving forward, we'll also provide quarterly updates on our progress. We also expect to further improve our oil price realizations once we connect to the Magellan Longhorn pipeline commencing as early as April of this year. Through this effort we expect to achieve LLS pricing, less about $7 a barrel for transportation, which represents a tremendous margin improvement for Diamondback. Although we expect to be pro rated until that pipeline reaches its full capacity, our initial commitment is at 6,000 gross barrels a day, escalating to 8,000 gross barrels a day when the pipeline is at full capacity in late 3Q or early 4Q of this year. With these comments complete, allow me to turn the call over to Tracy to review our financials.

Thanks, Travis. Let me echo Travis' thoughts and welcome everyone to our fourth quarter and full year 2012 earnings call. We are pleased and excited to report our first quarter and full year financial information as a public Company. In today's call, I will be quoting all financial information on a pro forma basis. The pro forma financial information reflects the contribution of Gulfport Energy's assets as if the contribution occurred on January 1, 2011.

During the fourth quarter of 2012 and the full year 2012, net income before income tax was $3.5 million and $25.1 million respectively. We recognized deferred tax assets and liabilities for temporary differences between the historical cost basis and tax basis of our assets and liabilities resulting from a change to a C Corp. from a limited liability Company. Those temporary differences resulted in a net deferred tax liability to us of approximately $54 million. This cost was recognized in the fourth quarter of 2012 with a corresponding non-cash charge to earnings. Our net loss after the non-cash income tax charge to earning during the fourth quarter of 2012 and the full year of 2012 was a $50 million loss and a $30 million loss respectively.

Our EBITDA for the fourth quarter was $15.4 million and for the full year 2012 was $62.9 million. Total revenues for the fourth quarter were $27 million and for the full year 2012 our revenues were $98 million. During the fourth quarter we had a gain on hedging activities of $600,000. This consisted of an unrealized gain of $1.7 million and a realized loss of $1.1 million. For the full year of 2012 we recorded a gain on hedging activities of $2.6 million. This full year hedging gain is compromised of an unrealized gain of $8 million offset by a realized loss of $5.4 million.

Turning to costs. Our combined direct and indirect lease operating expenses were $6.6 million or $15.68 per Boe. This is a quarter over quarter decrease from our third quarter cost of $18.04 per Boe. Our full year 2012 combined direct and indirect Loe was $23.3 million or $16.59 per Boe. Production tax for the fourth quarter was at $1.3 million and for the full year 2012 production tax was $4.8 million. G&A costs for the fourth quarter were $5.9 million or $13.93 per Boe. This is an increase from third quarter as a result of a one-time charge for IPO related costs.

Our full year 2012 G&A costs were $10.5 million or $7.45 per Boe. The fourth quarter 2012 DD&A expense of $10.1 million or $23.80 per Boe. Our full year 2012 DD&A expense was $34.2 million or $24.37 per Boe. As of December 31, 2012 we had no long-term debt related to our revolving credit facility and $135 million of undrawn borrowing capacity. In the first quarter, we had drawn down $30 million.

As we see the world today, we are currently positioned through a combination of expected operating cash flow and increases to our borrowing base to adequately fund and -- to adequately fund our drilling program through 2014. During the fourth quarter of 2012 capital expenditures were approximately $32 million, primarily for drilling and completion of wells and infrastructure. For the full year 2012 capital expenditures were approximately $147 million. This includes drilling completion, infrastructure, and land acquisition costs.

Turning to operational data. Total production for the fourth quarter was 422,800 Boe, of which 68% was oil and 18% was NGL. Full year 2012 we produced 1,403,600 Boe, of which 69% was oil and 17% was NGL.

Now turning to guidance. Based on our anticipated drilling program, we estimate our 2013 average daily production to be between 7,200 to 7,500 Boe per day. For 2013, the Company expects capital expenditure to be in the range of $270 million to $300 million, 67% of which will be focused on our horizontal development. We anticipate horizontal [walkoff] to be in the range of $7.5 million to $8.5 million per well and vertical well cost to be in the range of $2 million to $2.2 million per well. On the operational side, we project our direct operating expenses to be in the range of $8.50 to $10 per Boe and our indirect operating cost, which include our ad valorem tax and COPAS overhead charges, to be in the range of $2.50 to $3 per Boe. G&A is anticipated to be in the range of $3 to $5 per Boe and our DD&A in the range of $22 to $25 per Boe.

Turning to our hedging program, the Company's goal is to hedge between 40% and 70% of production throughout the year. Currently we have two hedges in place. Our first hedge, which is currently active, is for 1,000 barrels per day at $80.55 bench marked at WIT and ending in December of 2013. The second hedge, which was recently put in place, is the 1,000 barrels per day at $109.70, bench marked at Brent. This hedge will started in May of 2013 and continue for 12 months. This was placed in anticipation of the delivery of our barrels into the Magellan longhorn pipeline. With those comments complete, allow me to turn the call back over to Travis for some closing comments.

Thank you, Tracy. To summarize, we delivered strong results during the fourth quarter of 2012, which was our first quarter as a publicly traded Company. We're well on our way to delivering on our volume growth projections of almost 95% from our average production during 2012. We have positive early indications from a horizontal development with plans to drill 25 wells this year, along with 37 vertical wells. Our overall development costs on both horizontal and vertical well costs are trending down, along with our expense structure. We feel like we have the right assets and people to deliver on the exciting 2013. And we feel like we're off to a very good start.

On behalf of our Board and the employees of Diamondback Energy, I'd like to thank you for your participation today. This concludes our prepared comments. Operator, you can now open the call to questions.

(Operator Instructions)

Mark Lear of Credit Suisse.

On the -- just on the current rig cadence, I guess, what, four rigs running. I guess looking at early success on the horizontal front, I mean, do you think you could, I guess, move more of the focus toward horizontal versus vertical development or how do you see that playing out with some of the results you've had on the horizontal side?

Mark, what we're going to do is we are going to let results drive that decision. We're still early in the game and we would just start flowing back our second operated well down in Upton County. While we are encouraged on those results, we're going watch it and as those results dictate, I think it's fair to think we'll accelerate that horizontal development going forward into the future.

Also, encouraging to see you guys being able to pick up some additional Midland County lease hold. What do you think the ability to continue to do those kind of bolt-ons in the future is?

Yes, Mark. We described during the IPO road show just how difficult it is to pry acreage loose in this tightly held basin. And the way that we've been able to accomplish even these 2,500 acres is it's not a part-time job, it's really a fulltime effort to continue to have conversations with different folks to see if we can bolt-on these additional acreage. It's something we do every day. While I can't really forecast how successful we'll be going forward in bolting on acquisitions, I can tell you it's something we spend significant time on every day trying to make sure we can do the right acquisitions that are accretive to our current inventory.

Lastly on bond costs, you alluded to getting horizontal well cost down to that $7.5 million range. Are you there currently or is that something you see with new contracts you've got coming on? Just some color on that.

Well, I think it's bad karma to talk about completed well cost on these wells that I don't have completed yet. But I can -- just looking at the drilling side in term of days like I described, we're definitely less days and we're saving costs on -- relative to the AFE. If we can continue to repeat these fewer days on horizontal wells and come in at our completion costs on our horizontal wells, that's what's going to drive us towards the low end of that guidance. I mean, just to give you some color, we're -- we've got four horizontal wells we're fracking in the next five weeks. So there's still a lot of capital we're spending on these horizontal wells.

Great. Thanks a lot, Travis.

Gordon Douthat, Wells Fargo. Your line is open.

Another question on the horizontal program. Can you just provide some details on your inventory and what you've identified across your asset base from a horizontal location count? Then how might that be split between the B-bench and the other zones that you mentioned that are prospective across your acreage?

Sure, Gordon. Let me tell you what we've done first from a geoscience perspective. We've taken all of the -- all of our acreage and we've done some what we call pfh which is prosty fitness mapping. We've applied but we feel like our best industry cutoffs for those pfh [dignaism]. We've mapped five different shale horizons across our 52,000 acres. And then with those mapped, where there's adequate thickness in there, we laid in four horizontal wells per section.

That's the interlateral spacing there is four wells per section. That's where we come up with the 700 locations. You look at the 700 locations again, four across a section, about 50% of those are in the Wolfcamp A and B. So, about 300, a little over 300 are in the Wolfcamp A and B. The other 50% of those, the other 350, are split between -- I'll go top to bottom now.

They're split between the Clearfork, Wolfcamp C and the Cline. Those are the additional five zones. We're actually keeping our eye on some operators here that are -- that have some horizontal Spraberry wells, Spraberry shale wells. We have that Spraberry shale on our acreage base, as well, but I'm not including any of those in that 700.

And then for your program this year, can you remind me what the split will be between the B-bench and then the other zones.

Like I said in my prepared comments, all 25 of those wells are targeting the Wolfcamp B. But I think it's reasonable to expect in the second half of the year that we may test the Wolfcamp A. We know of some operators that are drilling in the Wolfcamp A now that are close to us. And depending on how their results come in, we may test a Wolfcamp A in the second half of the year. If we do make that decision, I'll provide additional color on that in some later calls.

Last one for Tracy. You mentioned the ability to fund your drilling programs through the end of 2014 with cash flow and borrowing base increases. What price deck does that assume?

Again, that would be us switching over to the LLS. That is closer to about $95 realized price on oil.

Okay. That's it from me. Thank you.

Kerr Freedman of Simmons and Company.

I'm curious with this 2,500 net acre acquisition, is that going to change the leasehold geometry in Midland County, do I drill longer laterals?

The way that those sections are laid out, no. They're perfectly suited for long laterals somewhere in that 7,500 to 8,000-foot lateral link and they're north/south. That's one of the reason we're so excited about them because they lay themselves out very, very nicely for horizontal development.

Then I was thinking about your horizontal drilling program and you are shifting there for the higher RORs. Specifically, as you increase your focus there, how does that impact your ability to HPP all your acreage?

Well, most of our leases are past their primary term. So they're in their continuous development phase. Most of our leases are on like 120 to 180-day continuous development clause. So, we'll probably always have some vertical drilling going on. And one of the reasons that we would do that it was to make sure we honor those continuous development clauses. So that's how we think about it. Obviously, we're not going to let any acreage expire because we pass over a development clause date.

Then last question from me. With the currently attractive rates in the debt market, how do you think about adding debt to the balance sheet to finance your planning in the coming years?

As Tracy just mentioned, we don't really see a gap, but we've got lots of opportunities now. So, we're in great shape with lots of opportunities in front of us. We'll continue to look at those opportunities and see if it makes sense for Diamondback to do that.

Great, thanks, guys.

Tim Rezvan of Sterne Agee.

I had a quick question on the Neil 8-1 well. We saw similar IPs to what Pioneer had previously published in the county. You guys had a slightly longer lateral. I was wondering if you could talk about what you did on that well versus any intelligence you have on what Pioneer did and how you can apply that going forward.

I'll let Pioneer talk about the result of their wells. But I will tell you what we did specifically on the Neil well. We followed what we feel like is the most -- the best way to frac these wells, which is a slick water job where we use about 300,000 pounds of sand per stage. And we split our horizontal up into about 240 to 250-foot inner stage distances. And that's where we get the 30 to 32-stage frac links.

When we were cleaning that well out, we got coil tubing stuck and by the time we got it back out, we actually lost about a month by the time we got everything cleaned out of that well. So, it's quite possible that we lost a little bit of reservoir energy. While we don't think it's going to impact the EUR, we might have lost a little bit of reservoir energy. But again, when I say we're excited about that Neil well results, let me tell you a little bit more why we're excited about it.

During the IPO road show, we guided people towards 500,000 to 600,000 barrels of reserves per 7,500-foot well. Since we've got some of our own wells on board and we've looked at industry, we've actually upped our expectations for horizontal wells. Still kind of in a risked way, but we're talking about 550,000 to 650,000 right now. In that Neil well, although it's early timeframe, that Neil well is performing at the top end of our type curve for the 550,000 to 650,000 barrel EURs.

And then lastly, you gave commentary on frac stages and lateral links for the next wells in the queue. I've noticed they've changed slightly from a slide deck you put out a few weeks ago. Is there anything material kind of in what makes you change? I noticed the Spanish Trail well you now talk about 19-stages. Just kind of curious what you've learned to make you kind of tweak your completion recipe.

Well, it's really what we're doing is trying to stay consistent with these lateral links. If we actually drilled a little bit longer lateral and if you just do the math about the 240-foot inter-distance right now, inner stage distance, that's all we're doing now is providing more precision on the exact lateral link, where that first frac gets initiated.

That has to do with the well bore jewelry we put down on the tow section. Then we back it up by 240-foot increments. We stayed consistent. And I may be more precise now than I was a couple of weeks ago because I have actual lateral link drilled now. But it's lateral link divided by 240 and that's the number of stages.

Okay. Thanks. That's all I had.

Ryan Oatman of SunTrust.

I want to shift to the northern Midland Basin. Looking at that Kemmer well, it certainly has had a very strong extended performance. Just doesn't look like it's declined the first few months. What sort of EUR should we expect from that well and do you expect better results here in Midland County versus Upton?

Yes. Let me talk specifically about the Kemmer well right now. It's been on line for about 5.5 months and it's [kummed] 57,000 Boe, of which, and this is kind of a good number for you, 85% of that's still oil. In 5.5 month, it's still got the real high oil cut. Currently doing about 150 barrels a day, 165 Mcf a day.

We did get -- since that well was a last year well, we did get Ryder Scott to include that in our reserve report at the end of 2012. And we've got ascribed to that well a little over 500,000 Boe's of which 71% is oil. Your more general question on Upton County versus Midland County. While we're extremely pleased with our early results in Upton County, we think the Kemmer well plus the wells that we're fracking right now, or will frac here shortly, we think are going to be a little bit better.

The shale's a little bit deeper. We think it continues to get a little bit more brittle, which mean the frac is a little easier to initiate and the rock cracks up a little bit better. So, we're just -- we're more excited about Midland County, but we are still excited about Upton County. We think good things are still in front of us in Midland County as we continue to report these results.

And what's the upcoming schedule for releasing the results in Midland County?

Well, I'll tell you, my canned answer is that we're going to report to you guys just like we're doing now in quarterly calls. But recognize that we've got some -- these horizontal wells will be nice catalyst for our performance. We could have some interim operation updates, but what I'm trying to kind of steer you away from is that I don't want to be talking about each one of these wells every time we bring one of them on.

Like I said, we've got four wells in the next five weeks. So, if we do an on-deal road show or go to some of these conferences, we'll probably have to provide an operation update in order to have something meaningful to talk about during these conferences. I may do an interim update. But as it sits right now, just know I promise you I'll talk to you about them in detail each quarter.

Perfect. Appreciate it, guys.

Eli Kantor of IBERIA Capital.

Good morning guys, nice quarter. Most of my questions have been answered. I did want to touch on your Crockett County acreage and any plans to test the Leonard Reservoir in Andrews County. Starting in Crockett, do you plan on spudding a pilot well this year? If so, is it going to be a horizontal or vertical well? What zones do you plan on assessing? What are your expectations regarding productivity?

Well, in Crockett County, you've heard me use the term fast fall-over. That's what we're going to do down in Crockett County, as well. Approached just recently, permitted some wells that are close to that acreage a little bit to the north. What we're going to elect to do is wait and see how some of the industry's activity supports our acreage down there before we do anything. When we do decide to go down there, though, specific to your question, we'll drill a vertical hold and look at the Wolfcamp A, Wolfcamp B and potential to C in the form of a whole core analysis and advanced core shale logging techniques. And then we'll probably suspend the well until we get our results back from the science that we attained and then come back and subsequently drill if we can economically support it.

Your second question was moving all the way up to Andrews County. And in Andrews County, we're just as excited about Andrews County in terms of the amount of hydrocarbons that are in place. We validated that through a lot of shale logging that we've done in Andrews County. It is a little bit more interspersed with some carbonate members because of its proximal nature to the shelf's edge. But we've done just recently in our most recent vertical well, we've taken sidewalk cores and we have done on-site laboratory analysis where we've done some kind of shale tests real time. And we're encouraged by the Wolfcamp B, also the Clearfork, up in that area.

Again, like we've talked of being fast followers, there's other operators up in Andrews County right now which are drilling in the A, the B, and the Clearfork, which is also known as the Leonard. So, we've got our eye on the ball there, as well, too. And as those results come in and we run economics and can find that we can support an economic horizontal well, we may come back to you with some ideas on drilling horizontal in Andrews County.

Travis, it looks like there are three completions from SM into the Leonard shale in Andrews County that are in the state data base. Wondering if you had a chance to take a look at their results and any kind of color related to those wells' performance.

Yes. Again, like on the Pioneer question, I'll let St. Mary talk about their wells. But you're right, the information is out there in the public domain. And yes, we've -- we do know quite a bit about those Clearfork or Leonard wells just based on the public available data. There's a little bit of difference there on the Clearfork and the Leonard.

Those wells tend to be a little bit up on the shelf's edge, where the majority of our acreage in Andrews County is kind of off the shelf edge. We're a little bit deeper in our Clearfork and Leonard member there. It sort of depends on the total horizontal drilling cost for those wells. And then the corresponding finding cost as it compares to what we think is available to us in the Wolfcamp B and the Wolfcamp A. It's something we're watching real closely. We'll just evaluate it and do the highest rate of return project first.

Okay. Great. Thanks very much.

Jason Wangler of Wonderlich Securities.

Just had one, Tracy, for you. I think the line that you said on the release was at 30 million. When is the next re-determination and do you have any indication how that's going to go?

Our next re-determination will be in this early spring. And I don't actually -- I mean, we will re-determine and evaluate our production reserves. And we expect to increase at that point. But I don't have any indication of what that will be at this point.

Okay. That's all I had. Thank you, guys.

Jeffrey Connolly of Brean Capital.

You guys have two horizontal and two vertical rigs running. Are there any plans to pick up another rig?

Well, what we're doing -- you heard me talk about cycle time and how fast we're drilling these wells. So there's one of two things. We can either get all of our wells drilled, all of our horizontal wells drilled due to the fact that we're drilling them faster with two rigs. Or, as I think Mark Lear was asking me, we can -- as results continue to drive our decisions, we could pick an additional horizontal rig up in the second half of the year. We're going to let that strategy be driven by these well results. Better results, think about more acceleration.

Then one for Tracy. Can you give us any guidance on the tax rate for 2013?

We're using about 35%.

Okay, great. Thank you very much.

I'm showing no further questions in the queue at this time. I'll hand the call back to management for closing remarks.

Thanks again to everybody participating in today's call. I know this is a busy time for you guys, because I can judge that by the late night releases and early morning releases on the companies you're writing on. I appreciate you carving some time out of what I know is a busy schedule.

Listen, if you've got any more questions that we didn't answer, we are going to be in all week. So, just reach out me or Tracy or Jeffrey and we'll get your questions answered. So have a great rest of the day. And again, we really appreciate kind of having this first quarter behind us and you guys taking time out today. So, thanks again.

Thank you. Ladies and gentlemen, this concludes the conference for today. You may all disconnect and have a wonderful day.