Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Diamondback Energy Inc. (NASDAQ:FANG)

Q42012 Earnings Call

February 26, 2013 10:00 am ET

Executives

Jeffrey Goldberger - Investor Relations - KCSA Strategic Communications

Travis Stice - President and Chief Executive Officer

Teresa Dick - Chief Financial Officer, Senior Vice President

Analysts

Mark Lear - Credit Suisse

Gordon Douthat - wells Fargo

Kerr Friedman - Simmons & Company

Tim Rezvan - Sterne Agee

Ryan Oatman - SunTrust Robinson Humphrey

Eli Kantor - IBERIA Capital Partners

Jason Wangler - Wunderlich Securities

Jeffrey Connolly - Brean Capital

Operator

Good day, ladies and gentlemen, and welcome to the Diamondback Energy's 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 that 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. You may begin.

Jeffrey Goldberger - Investor Relations - KCSA Strategic Communications

Thank you, Mimi and good morning and welcome everyone to Diamondback Energy's fourth quarter earnings conference call. My name is Jeffrey Goldberger and I am with KCSA Strategic Communications, Investor Relations counsel to Diamondback.

Representing the company with me today are Travis Stice, Chief Executive Officer, Teresa Dick, Chief Financial Officer, Russell Pantermuehl, Vice President of Reservoir Engineering. We hope you have had an opportunity to review the release we issued at the close of business yesterday. Let me quickly outlay the agenda for today's call.

Travis will begin with a brief introduction to Diamondback and a quick overview of our operating results. Teresa will then bring you to the financial details including the income statement and balance sheet along with key operational metrics for the three and twelve months ended 12/13/12. Finally Teresa will provide full-year 2013 guidance and then open up the call for 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 the 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 the results to differ materially from those expected by the management of Diamondback. Diamondback Energy undertakes no obligation to update or revise any forward-looking statement.

During our call today, we will reference certain non-GAAP financial measure 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 re-broadcast 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 1:00 PM Eastern Tim through Tuesday March 5, 2013 at 11:59 PM Eastern Time. To access the replay, call 855-859-2056 in the U.S. and Canada or 404-537-3406 for international callers and enter the confirmation code, 12520719. The webcast will also be on the company's website for 30 day.

Now, its my pleasure to turn the call over to Travis Stice.

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, 2012. Since this our first earnings conference call, I want to take the opportunity to provide a detailed overview of Diamondback Energy but before doing so I would like to just take a moment to describe our leadership team and some of our guiding principles.

When I joined Diamondback in April 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 the team is relatively new to Diamondback, with the exception of the CFO, Teresa Dick, who has been with Diamondback since its inception, most of us have worked together at the likes of Burlington Resources, ConocoPhillips, 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 have established as creating successful strategies from our collective prior experiences. Not only to ensure the long-term success of Diamondback, but also the whole leadership accountable to our employees and our investors. These guiding principles are grounded in the following concepts, superior execution, transparency and communications, and delivering (inaudible) margins

So turning to our underlying story, Diamondback Energy is an independent EMP that’s headquartered E&P that is headquartered in Midland, Texas, and focused on the Permian basin primarily within the Wolfberry Trend. With holdings of just under 52,000 net acres at the end of 2012, Diamondback is one of the limited number of publicly traded pure operators in the Permian basin, which allows investors to participate directly in the tremendous resurgence of drilling activity and corresponding volume growth that have taken place in the Permian Basin since 2009.

In addition to developing our existing acreage, we also seek to make both on land acquisitions around our existing core areas in the basin, where we 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 tracts have high potential for Wolfcamp shale development and layout 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 plus locations. Of these 700 plus horizontal sites identified 50% of those are located in either the Wolfcamp B of the Wolfcamp A. Our acreage expands from Andrews County to Crockett County in relatively contiguous blocks, which lends itself to horizontal developments in economies of scale.

Now some specifics on the fourth quarter and full year 2012. Just as a reminder, when we went public during the fourth quarter of last year, we were really just getting this machine started. Production for the fourth quarter of 2012 on a pro forma basis totaled 4.6 MBoe per day, up 18% from the third quarter of 2012. Year-end 2012 proved reserves totaled 40.2 million Boe and consist 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 PUDs to the probable reserves category. Overall, we replaced 337% of 2012 production with reserve additions excluding revisions which were 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 are not eliminating our vertical drilling activities, we plan to overweight towards horizontal drillings through 2013, with roughly two thirds of capital allocated to horizontal wells.

Driving this decision is a couple of factors. First horizontal drilling activities migrating north in the Midland basin, where we believe the shale is more brittle, its deeper and its at higher pressure than in the south east portion of Midland basin where the original horizontal Wolfcamp development began. 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 de-risked 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 that rate of return will be higher for horizontal wells due these high initial flow rates, the development cost we are 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 activities there has taken place in the Wolfcamp B which is the shale member we currently think offers the best return. However there is 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 Kemmer 4209H and the Janey 16H are promising having been drilled to lateral lengths of 3,733 the and 3,842 feet, respectively with each of these well on track to achieve the ERs of between 400,000 and 500,000 barrels per well. We are also encouraged by the strong results recently delivered by our 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 Kemmer and the Janey wells, we have three additional horizontal wells in Midland County and four horizontal wells in Upton County. Here are some updates on our drilling activities in Midland County. The Spanish trail, 25-1H is drilled with a lateral length of 4,617 feet and is scheduled for 19 stage frac to being in early March. The frac on this well will also be monitored using microseismic which is important to us as we settle on inter lateral spacing, ideal port 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 of 25-2H is drilling with a target lateral length of around 4,800 feet and is also scheduled for the 19 stage frac job immediately following the 25-1H frac in mid-March.

Finally, the serenium 3812H which is non-operated well and which Diamondback has 42% working interest was drilled to a lateral length of 4,461 feet and just recently completed a 18 day frac. The well is currently flowing back and just started cutting oil over the weekend. Our drilling activity in Upton County where we are now drilling our fifth well is benefitting from the continued improvements in our drilling program as measured by the reduction days required to reach TD. We think we will similar improvements and reduced days for our horizontal wells in Midland County.

The Neal 8-1H was drilled to a lateral length of 7,652 feet, and we have 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 days with an 85% oil component. We are 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. That’s a two stream number and that’s about 87% oil. So that kind you gives you an indication of why we are still excited about that well.

Its sister well, the Neal 8-2H was drilled to a lateral length of 6,685 feet and s 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 undergoing a 19 stage frac and should begin flow back early next week.

The last well, the well we are drilling in Upton County, the Kendra 1H, it has got a planned lateral of 7,550 feet. It looks like we will reach TD in 20 days or less.

There are a couple of things worth noting. First, as I mentioned, we continue to improve the efficiency of our drilling program. So if you just look at the 32 days it took us to reach roughly a 3,800 foot lateral in Janey well last year, about a year this time, it took us roughly 24 days to reach TD for both the Neal 8-1H and 8-2H 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 lateral, so not only we are drilling longer laterals, we are 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 expectations 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, the development cost 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.

Now speaking of lateral length, our optimum lateral lengths going forward will be in that 7,500 to 8,000 foot range and we are targeting typically around an average of 30 to 35 frac stages. Moving towards these 7,500 foot laterals should result in an improved S&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 its activity. We will watch closely what's going on and we will be fast followers with these model laterals. We will also drill a one mile lateral where that’s required by lease geometry.

Looking at our vertical drilling program. Diamondback will continue to make the most of our portfolio of multiyear 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 been able to reduce our SPUD 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 68 days in the first quarter 2011 42 days in the fourth quarter of 2012. Like the cost story on horizontal wells, as we repeat this performance, cost should migrate towards the low end of our guidance for these vertical wells of $2 million to $2.2 million per well.

As noted earlier Diamondback is dedicated to increasing their margins. To achieve this, we have allocated approximately $10 million to $15 million in 2013 to improve our infrastructure and reduce our LOE. In Midland County, we are in the process of migrating water disposal from truck carriers to pipeline which will reduce our LOE by approximately $2.50 a barrel. Similarly, we are migrating from oil haul trucks to pipeline that will improve realizations by $1.50 to $2 a barrel. We also plan to tie together our tank vetters 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 commercial software disposal well. The monthly savings on just those on volumes alone will translate to roughly $0.50 per barrel reduction in our LOE field wide. Combine these efforts to support our goal to reduce our direct LOE to $8.50 to $10 a barrel by the end of 2013, which excludes our indirect expense of adding lower overhead between $2.50 and $3 a barrel. We continue to the look for ways to drive additional LOE reductions and as we work towards achieving these best-in-basin operations, moving forward we will also provide quarterly updates on our progress.

We also expect to further improve our oil price realizations once we connected 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 prorated until that pipeline reaches its full capacity, our initial commitment as 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 Teresa to review our financials.

Teresa Dick

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 of 2012, net income before income tax was $3.5 million and $25.1 million, respectively. We have 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 earnings 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 unreleased 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 comprised 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 quarter-over-quarter decrease from our third quarter cost of $18.04 per Boe. Our full year 2012 combined direct and indirect LOE is $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 cost for the fourth quarter was $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 cost were $10.5 million or $7.45 per Boe.

The fourth quarter 2012 DD&A expense is $10.1 million or $23.80 per Boe. Our full year 2012 DD&A expense is $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 unexpected operating tax flow and increases to our volume base 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 expenditures to be in the range of $270 million to $300 million, 67% of which will be focused on our horizontal development. We anticipate horizontal walk off 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.

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 and corporate 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 benchmarked at WTI and ending in December 2013. The second hedge which was recently put in place is for 1,000 barrels per day at $109.70 benchmarked at Brent. This hedge will start in May 2013 and continue for 12 months. This was placed in anticipation of the delivery of our barrels in to the Magellan Longhorn pipeline.

With those comments complete, allow me to turn the call back over to Travis for some closing comments.

Travis Stice

Thank you, Teresa. To summarize, we delivered strong results during the fourth quarter of 2012 which was our first quarter as a publicly traded company. We are 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 our horizontal development with plans to drill 25 wells this year along with 37 vertical wells. Our overall development costs on both horizontal and vertical 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 are off to a very good start.

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

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from Mark Lear of Credit Suisse. Your line is open.

Mark Lear - Credit Suisse

Just on the rig cadence, I guess four rigs running, I guess looking at early success on the horizontal front, do you think you could move more of the focus towards horizontal versus vertical development? Or how do you see that playing out with some of the results you have had on the horizontal side?

Travis Stice

Mark, what we are going to do is we are going to let results drive that decision. We are still early in the game and we have started flowing back our second operated well down in Upton County. So while we are encouraged on those results, we are going to watch and as those results dictate, I think it is fair to think we will accelerate that horizontal development going forward in the future.

Mark Lear - Credit Suisse

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

Travis Stice

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

Mark Lear - Credit Suisse

Got you, and then, just lastly on cost. You definitely 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 have got coming on? Can you just give some color on that?

Travis Stice

Well, I think its 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 terms of days, like I described, we are definitely less days and we are saving cost relative to day fee. So if we can continue to repeat these fewer days on horizontal wells, and come in at our completion cost on our horizontal wells, that’s what's going to drive us towards the low end of that guidance. Just to give you some color, we have got four horizontal wells we are fracing in the next five weeks. So there is still a lot of capital we are spending on these horizontal wells.

Mark Lear - Credit Suisse

Great, thanks a lot, Travis.

Operator

Our next question is from Gordon Douthat of wells Fargo. Your line is open.

Gordon Douthat - wells Fargo

So another question on the horizontal program. Can you just provide some details on your inventory and what you have identified across your asset base from an 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?

Travis Stice

Sure, Gordon. Let me tell you what we have done first from a geoscience perspective. We have taken all of our acreage and we have done some, what we call Phi-H, which is porosity thickness mapping and we have applied but we feel like our best industry cutoffs for those Phi-H thicknesses and we have mapped five different shale horizons across our 52,000 acres. Then with those maps, where there is adequate thickness in there, we laid in four horizontal wells per section. So that’s the inter lateral spacing there. Its four wells per section. That’s where we come up with the 700 locations.

When you look at the 700 locations again, four across the section, about half of those are in the Wolfcamp A and B. So about well over 300 in the Wolfcamp A and B. The other half of those, the other 350 are split between, we will go top to bottom now, they are split between the Clear Fork, the Wolfcamp C and the Cline. So those are the additional five zones and we are actually keeping our eye on some operators here that have some horizontal Spraberry shale wells and we have that Spraberry Shale on our acreage base as well but I am not including any of those in the 700.

Gordon Douthat - wells Fargo

Okay, that’s helpful. Then for your program this year, can you remind me what the split will be between the B bench and then the other zones?

Travis Stice

Like I said in my prepared comments, all 25 of those wells are targeting the Wolfcamp B but I think it's reasonable expect in the second half of the year that we may test the Wolfcamp A. We know if 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 but if we do make that decision, I will provide additional color on that in some later calls.

Gordon Douthat - wells Fargo

Okay, thank you and then last one for Teresa. You mentioned the ability to fund your drilling programs through the end of 2014 with cash flow and borrowing base increases. What price tag does that assume?

Teresa Dick

Again that will be us switching over to the LOS and that is closer to about 95 realized price on oil.

Operator

Our next question is from Kerr Friedman of Simmons & Company. Your line is open.

Kerr Friedman - Simmons & Company

I am curios with this 2,500 net acres acquisition. Is that going to change the leasehold geometry in Midland County to longer laterals?

Travis Stice

The way that those sections are laid out, no. They are perfectly suited for long lateral, somewhere in that 7,500 to 8,000 foot lateral length. They are north-south. So that’s one of the reasons we are so excited about because they lay themselves up very, very nicely for horizontal development.

Kerr Friedman - Simmons & Company

Okay, great and then, just thinking about your horizontal drilling program and you shooting there for the higher RORs. Specifically, as you increase your focus there, how does that impact your ability to Hpp all your acreage.

Travis Stice

Well, most of our leases are past their primary terms. So they are in their continuous development phase. Most of our leases are on like 120-day to 180-day continuous development clause. So we will probably always have some vertical drilling going on and one of the reasons that we would do that it will be to make sure we honor those continuous development clauses. So that’s sort of how we think about it. Obviously we are not going to let any acreage expire because we are passed over development clause date.

Kerr Friedman - Simmons & Company

Okay, great and then last question for me. With currently attractive rates in the debt market, how do you think about adding debt to the balance sheet to finance your development planning in your coming years?

Travis Stice

We know, as Teresa just mentioned, we don’t really see a gap but we have got lots of opportunities now. We are in great shape with lots of opportunities in front of us. So we will just continue to look at those and it makes from sense for Diamondback to do that.

Operator

Your next question comes from Tim Rezvan of Sterne Agee. Your line is open.

Tim Rezvan - Sterne Agee

I had a quick question on the Neal 8-1H 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 are going to apply that going forward?

Travis Stice

I will let Pioneer about the results of their wells. But I will tell what we did specifically on the Neal well. We followed what we feel like is 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 in to about 242 to 250 foot inter stage distances. 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 out, we lost about a month by the time we got everything cleaned out of that well. So it is quite possible that we lost a little bit of reservoir energy. While we don’t think its going to impact the EUR, we might have lost a little bit of reservoir energy.

But again, when I say, we are excited about that Neal well results, let me tell you a little bit more about why we are 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 have got some of our wells onboard and we have looked at industry, we have actually upped our expectations for horizontal wells. Still kind of in a risk way, but we are talking about 550,000 to 650,000 right now in that Neal well. Although its early timeframe, that Neal well is performing at the top end of our type curve for the 550,000 to 650,000 barrel EURs.

Tim Rezvan - Sterne Agee

Okay, Thanks for that color. Lastly, you gave comments on your frac stages and lateral lengths for the next wells in the queue. I have noticed that its changed slightly from a slide deck you put out a few weeks ago. Is there anything material? What makes you change? I notice the Spanish trail well, you are now talking about 19 stages. I am just curious what you have learned to make you tweak your completion recipe?

Travis Stice

Well, what we are doing is trying to stay consistent with these lateral lengths. If we actually drill a little bit longer lateral and if you just do the math about the 240 foot inner distance right now, inner stage distance, that’s all we knew. That’s all we are doing now, providing more precision on the exact lateral length where that first frac gets initiated and its has to deliver with the well bore jewelry we put down on the toe section and then we backed it up by 240 foot increments.

So we stay consistent and I maybe more precise now than I was a couple weeks ago because I have actual lateral lengths drilled now. But its lateral length of about 240 and that’s in other stages.

Operator

Our next question comes from Ryan Oatman of SunTrust. Your line is open.

Ryan Oatman - SunTrust Robinson Humphrey

I want to shift through the Northern Midland basin. Looking at that Kemmer well, it certainly has had a very strong extended performance. This doesn’t look like it has declined the first few months. But what sort of EURs should we expect from that well? Do you expect better results here in Midland County versus Upton?

Travis Stice

Yes, let me talk specifically about the Kemmer well right now. It has been online for about five and half months. It is 57,000 Boe, of which, and this is kind of a good number for you, 85% of that is still oil. So in five and half months, it's still got the real high. Currently doing about 150 barrels a day and 165 MCS a day. Since that well is a last year, well we did get Ryder Scott due to include that in our reserve report at the end of 2012 and we have got ascribe to that well a little over 500,000 Boes of which 71% is oil.

Now your more general question on Upton County versus Midland County. While we are extremely pleased with our results in Upton County, we think that the Kemmer well plus the well that we are fracing right now or will frac shortly, we think are gong to be able to be a bit better.

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

Ryan Oatman - SunTrust Robinson Humphrey

Okay, great. What's the upcoming schedule for releasing the results in Midland County?

Travis Stice

Well, I will tell you, my kind answer is that we are going to report to you guys just like we do now on quarterly calls, but recognize that we got some these horizontal wells will be a nice catalyst for our performance. We could have some interim operational updates but what I am trying to 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 have got four wells in the five weeks. So if we now do a road show or go to some of these conferences, we will probably have to operation update in order to have something meaningful to talk about during these conferences and so I made you an interim update but as it sits right now, just know our promise, and I will talk to you about them in detail each quarter.

Operator

Our next question comes from Eli Kantor of IBERIA Capital Partners. Your line is open.

Eli Kantor - IBERIA Capital Partners

Most of my have been answered. I did want to touch on your Crockett County acreage and any plans to test that Leonard reservoir in Andrews County? Starting in Crockett, you plan on starting a pilot well this year. If so, is it going to be horizontal or a vertical well? What zones you plan on assessing? What are your expectations regarding productivity?

Travis Stice

Well, in Crockett County, you heard me use the term fast follower. That’s what we are going to do down in Crockett County as well. We approached just recently. Permitted some oils that are close to that acreage a little bit to the north and we are 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 will drill a vertical hull and look at the Wolfcamp A, Wolfcamp B and potential to see in the form of the whore core analysis and advanced core shale logging techniques. Then they will probably just spin the wheel until we get our results back from the signs that we obtained and then come back and subsequently drill, if we can economically support it.

And your second question was moving all the way up to Andrews County. In Andrews County, we are just as excited about Andrews County in terms of the amount of the hydrocarbons that are in place and we validated that through a lot of shale logging that we have 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 have done just recently, in more most recent vertical well, we have taken sidewalk cores, and we have done on-site laboratory analysis where we have done some shale tests real time. We are encouraged by the Wolfcamp B, also the Clear Fork up in that area.

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

Eli Kantor - IBERIA Capital Partners

Travis, it looks like there are past three completions from SM in to the Leonard shale and Andrews county that earned the state database. I am wondering if you have a chance to take a look at their results, and any kind of color related to those wells performance.

Travis Stice

Yes, again, like on the Pioneer question, I let St. Mary talk about their wells, but you are right. The information is out there in the public domain.. yes, we do know quite a bit about those Clear Fork or Leonard wells just based on the publicly available data.

There is a little bit of difference there are clear forking on these Leonard wells tend to be a little bit up on the shale's where the majority of our average in Andrews county is off the shelf. So we are a little bit deeper in our Clear Fork and Leonard a member there.

This depends on the total horizontal drilling cost for those well and then the corresponding timing cost as it compares to what we think is available to us in the Wolfcamp B and the Wolfcamp A. So it is something we are watching real closely and we just evaluated and due to highest rate of return project first.

Operator

Our next question comes from Jason Wangler of Wunderlich Securities. Your line is open.

Jason Wangler - Wunderlich Securities

Just had one, Teresa for you. I think the line that we said on the release was that $30 million. What is the nice redetermination and do you have any indication of how that’s going to go?

Teresa Dick

Our initial determination will be in the early spring and I don’t actually, we will re-determine and valuate our production and reserves and we expect to increase at that point. But I don’t have any indication of what that will be at this point.

Operator

Thank you, our final question comes from Jeffrey Connolly of Brean Capital. Your line is open.

Jeffrey Connolly - Brean Capital

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

Travis Stice

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

Jeffrey Connolly - Brean Capital

Okay, thanks. Then one for Teresa. Can you give us any guidance on the tax rate for 2013?

Teresa Dick

We are using about 35%.

Operator

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

Travis Stice

Thanks again to everybody participating in today's call. I know this was a busy time for you guys because I can judge that by the late night release and early morning releases on the companies you are right now. So I appreciate you carving some time out of what I know is a busy schedule. Listen, if you got any more questions that we didn’t answer, we are going to be in all week. So just reach out to me or Teresa or Jeffrey and we will get your questions answered. So have a great rest of the day and again, we really appreciate, having first quarter behind us and you guys taking time out today. So thanks again.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Diamondback Energy's CEO Discusses Q4 2012 Results - Earnings Call Transcript
This Transcript
All Transcripts