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Rosetta Resources (NASDAQ:ROSE)

Q2 2014 Earnings Call

August 05, 2014 11:00 am ET

Executives

Antoinette D. Green - Vice President of Investor Relations & Planning and Officer

James E. Craddock - Chairman, Chief Executive Officer and President

John E. Hagale - Chief Financial Officer and Executive Vice President

John D. Clayton - Chief Operating Officer and Executive Vice President

Analysts

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Chris Stevens - KeyBanc Capital Markets Inc., Research Division

Irene O. Haas - Wunderlich Securities Inc., Research Division

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Brian D. Gamble - Simmons & Company International, Research Division

Will Green - Stephens Inc., Research Division

Joseph Patrick Magner - Macquarie Research

Operator

Good morning. Welcome to Rosetta Resources Second Quarter 2014 Earnings Conference Call. Joining us this morning from Rosetta are the following individuals: Jim Craddock, Chairman, President and Chief Executive Officer; John Hagale, Executive Vice President and Chief Financial Officer; John Clayton, Executive Vice President and Chief Operating Officer; Toni Green, Vice President, Investor Relations and Planning.

Today's conference call is being recorded. [Operator Instructions] If you are not able to participate in the conference call, an audio replay will be available from August 5, 2014, 2:00 p.m. Central through August 12, 2014, 11:59 p.m. Central by dialing (855) 859-2056 or for international, (404) 537-3406 and entering conference code 67206995. A replay of the conference call may also be found on the company's website, www.rosettaresources.com. To access the replay, click on the Investor Relations section of the company's website and select Events.

At this time, I'd like to turn the call over to Toni Green. Ms. Green, you may begin your conference.

Antoinette D. Green

Good morning, and thank you for joining us for our second quarter 2014 earnings conference call. As a reminder, there are slides that accompany our presentation today available on our website at www.rosettaresources.com. You can access the slides by logging in to the webcast or clicking on the link that takes you directly into the slides. I would also remind you that certain statements included in this morning's conference call, presentation and Q&A session may be forward-looking and reflect the company's current expectations and forecast of future events based on the information that is now available. Please refer to the Safe Harbor statements in our earnings release for more information.

With that disclaimer, let me review our agenda for the call. Jim Craddock will open with an overview of our second quarter 2014 performance. Next, John Hagale will provide a brief financial review of the period, followed by John Clayton, who will discuss our operating results. Jim will then open the lines for Q&A. [Operator Instructions] Let me now turn the call over to Jim.

James E. Craddock

Thanks, Toni. Good morning, everyone. We appreciate you joining us this morning. We had a great second quarter, and we're very pleased to report our progress in the Delaware Basin as well as in Eagle Ford. The first 6 months of 2014 was a productive time for Rosetta as we made major headwind on evaluating and delineating our Permian acreage position. We also moved further along on the development of our Eagle Ford leases and testing the Upper Eagle Ford pilots. We remain on track to meet or exceed our objectives for the year, and we're looking forward to that -- to maintaining that momentum into 2015.

Let's talk a bit about what we accomplished this quarter. We set another round of records for the quarter in daily total equivalent production, daily oil production and daily natural gas liquids production. We increased total daily equivalent production by 26% versus 2013 and 13% compared to the first quarter of this year. We completed 5 operated horizontal wells in Reeves County, 1 of which had our highest gross 7-day IP rate to date. We reduced our Eagle Ford total well cost guidance approximately 10% by implementing a new stimulation design. We increased our production and capital guidance and updated per unit expense guidance. And we reorganized our company into 2 divisions, Permian Basin and South Texas, to enhance focus on both of our core areas.

Let's review our second quarter highlights in some more detail. Production for the quarter averaged 61,500 barrels of oil equivalent per day, an increase of 26% from the same period in 2013 and 13% from the prior quarter. Our production growth was driven by strong performance from Briscoe Ranch, Tom Hanks as well as the latest horizontal results in Reeves County. Oil production in the second quarter averaged 19,000 barrels per day, an increase of 56% from 2013. Natural gas liquids daily production also increased by 16% compared to the prior year. Eagle Ford production grew to approximately 57,000 barrels of oil equivalent per day, equating to 21% year-over-year and 14% quarterly versus the prior quarter. The Permian area contributed 4,500 barrels of oil equivalent per day in the second quarter, a 5% increase versus the first quarter, despite very little contribution from our recent completions.

Our technical teams continued to increase their understanding of our Reeves County area, resulting in improved well completion performance. We are also making significant progress in delineating the asset, which will ultimately translate into increased Permian production. With that said, another significant accomplishment in the quarter was the completion of 5 operated horizontal wells in the Reeves County. One of the wells, the Calamity Jane 22 #1H, had a gross 7-day IP of approximately 2,000 barrels of oil equivalent per day from the Wolfcamp A, Rosetta's highest 7-day IP since entering the basin. We successfully completed a 3 well pad of operated Wolfcamp A wells with gross 7-day IPs ranging from 1,200 to 1,400 barrels of oil equivalent per day. In addition, we completed a New Ventures well, our first horizontal test in the Wolfcamp C bench. The Roy Bean 42 #1H was tested at a gross 7-day IP of 360 barrels of oil equivalent per day from the Wolfcamp C. In early July, we completed a sixth well, a New Ventures test to the Third Bone Spring. The Johnny Ringo 9 #2H had a gross 7-day IP of approximately 1,300 barrels of oil equivalent per day, our first horizontal completion from the Third Bone Spring.

Since initiating Permian operations last year, we have completed 10 operated horizontal wells producing from multiple benches. We plan to complete another 6 to 8 operated horizontal wells during the third quarter, including another Third Bone Spring test and an Upper Wolfcamp horizontal well with a 7,500-foot lateral length. Industry horizontal activity continues at a brisk pace on and around our Reeves County position, and we will discuss some of the activity later in the call. We are pleased with the results of our Permian horizontal program and look forward to updating you in future calls.

In the Eagle Ford, we are reducing our estimated total well cost by $500,000 per well. We're now projecting well cost at Gates Ranch, Briscoe Ranch, L&E, Vivion and Tom Hanks to range from $5.5 million to $6 million, a decrease from the previous range of $6 million to $6.5 million. The decrease is a result of changes in our completion design, including proppant type and concentration. We'll discuss the design changes in more detail in our operational remarks.

As detailed in our earnings press release, we're updating our 2014 guidance for production, capital and expenses. Based on the favorable results we've accomplished in our core areas, we increased the full year 2014 average daily production guidance to a range of 63,000 to 66,000 barrels of oil equivalent per day. The update results in a 2,000 BOE per day increase in the midpoint when compared to the previous guidance range of 60,000 to 65,000 BOEs per day. The new target range represents approximately 30% year-over-year production growth. We also increased our capital guidance by $100 million to $1.2 billion for the year, excluding acquisition capital. We previously communicated that we were seeing strong momentum in executing our capital program. And through the first 6 months, we've spent $753 million or roughly 63% of total capital for the year. Rather than slow down in the fourth quarter, it makes sense to continue that momentum into next year.

Finally, we recently reorganized the company to create 2 divisions, each headed by a Vice President. The Permian division and the South Texas division structure provides increased focus on what we now see as 2 very strong core areas. I'm very pleased with where we are and where we stand at this point and look forward to what lies ahead for Rosetta in the remainder of this year and into 2015.

Now let me turn the call over to John Hagale, who will provide a summary of our financial results.

John E. Hagale

Thanks, Jim, and welcome, everyone. As a reminder, all of the information I'm reviewing today is contained in our 10-Q as well as our press release, both of which were filed with the SEC yesterday and are available on our website.

Net income for the second quarter of 2014 was $14 million or $0.23 per diluted share versus net income of $75 million or $1.27 per diluted share for the same period in 2013. Adjusted net income for the quarter, that's non-GAAP, was $50 million or $0.82 per diluted share versus adjusted net income of $52 million or $0.88 per diluted share in 2013. Second quarter 2014 adjusted net income excludes unrealized derivative losses of $44 million and loss on debt extinguishment of $13 million. The after-tax total for those adjustments was $36 million. The decrease in adjusted net income was primarily attributable to increased DD&A expense, increased interest expense and higher realized loss on derivatives, which was partially offset by the higher production and higher realized prices.

Revenue for the second quarter was $221 million compared to $237 million for the same period in 2013. Second quarter revenues, excluding unrealized derivatives, was $265 million in 2014 and $194 million in 2013. Please note that our oil revenue includes condensate sales, which represent about half of the oil production. Our second quarter average realized oil price, when you exclude derivatives, was $93.99 per barrel. That's up $1.21 from the prior year and up $3.37 from the first quarter average of $90.62. Our realized oil price for the second quarter was slightly lower relative to the LLS index, primarily due to continued pipeline constraints in the Permian Basin. Due to those constraints, we are lowering our expected realized price for the second half of the year to roughly LLS minus $12 to $14, and that's total company pricing.

As Jim mentioned, we updated our expense guidance for 2014 in yesterday's earnings release, and we included the numbers again on Slide 4. We actively seek opportunities to add derivative positions to our production when pricing conditions warrant as a part of our active and disciplined hedging strategy. A detailed summary of our derivative position, as of July 31, is attached to the earnings release. Lastly, on a financing front, on May 29, we completed a public offering of $500 million aggregate principal amount of 5.875% senior notes that are due in 2024.

Now let me turn the call over to John Clayton.

John D. Clayton

Thanks, John, and good morning, everyone. As usual, I'll provide you with a quick overview of our operating results for the quarter and then spend some time updating you on a few of the catalysts that we have been working on. This quarter, I'll discuss our Permian horizontal program in Reeves County, our Upper Eagle Ford well performance and a major step change we are making in the Eagle Ford with our completion design.

Let's begin with our operational performance. Excluding acquisitions, capital spending for the quarter was $392 million. We drilled 34 gross operated wells and completed 37. We also placed 44 gross operated well on production during the quarter. Our total second quarter daily production averaged 61,500 barrels of oil equivalent per day, up 26% from the prior year and 13% higher than the first quarter. Total Eagle Ford production in the second quarter was 57,000 BOEs per day, up 21% from a year ago and 14% higher than first quarter. The Permian Basin contributed 4,500 BOEs per day in the second quarter, a 5% increase versus the prior quarter. The total company second quarter 2014 production rate includes 19,000 barrels of oil per day and 21,000 barrels of NGLs per day. Oil production for the quarter increased by 56% compared to last year. Oil production represented 31% of total production, up from 25% a year ago.

Slide 5 in the slide deck shows our total resource and production growth trends since 2009, the year of our initial Eagle Ford discovery well. The chart highlights the growth profile of our Eagle Ford production and also our Permian's increasing contribution to our overall company's production. Also included on the chart is our actual production through the first half of this year, along with estimated second half production, which is now based on our new full year guidance range of 63,000 to 66,000 BOEs per day. Our new guidance results in a 30% growth rate year-over-year, up from the prior guidance of 25%.

Eagle Ford development activities were ongoing during the quarter, primarily at Gates Ranch and on our Central Dimmit County leases. We operated 4 rigs in the Eagle Ford during the second quarter, drilling 21 wells. We also completed 28 wells and placed 31 on production. At Gates Ranch, third row [ph] activity continued with 27 wells completed and 10 wells drilled throughout the quarter. 18 Gates Ranch wells were placed on production in May, another 4 wells were brought online in June. In our Central Dimmit County area, 8 wells were drilled on the L&E lease and 2 wells were put on production at Light Ranch. At Briscoe Ranch, 1 well was drilled and 1 well was completed and brought online in June. On our Tom Hanks lease, we drilled 1 well and placed 6 wells on production. Finally, during the quarter, we drilled 1 horizontal well at Encinal.

That's a quick tour of our activity during the quarter. So now let's move to the Permian Basin and discuss our horizontal program. If I could summarize our Permian for the quarter, I would say that we are definitely seeing our best well results to date. I would also say that we have modified our completion designs, and we are definitely seeing the benefits of those changes.

So please turn to Slide 7, and let's look at the well results. This is an updated map of our Reeves County position and the current development plan that we provided to you last quarter. In yellow are the leases where we have greater than 50% working interest and we operate. In the areas in light gray, we have less than 50% working interest and we do not operate. The dotted lines in the background on both our operated and nonoperated acreage are technically vetted inventory. The wells in solid blue are the horizontal wells that Rosetta has completed to date. Since our last call, the momentum of our horizontal delineation program has picked up considerably. We successfully completed 1 Third Bone Spring New Ventures well, 4 Wolfcamp A wells and 1 Wolfcamp C New Ventures well. While still early in our a program, we have essentially doubled the number of horizontal producers, and we are very pleased with the results of our most recent completions.

So let's review those completions in more detail, and let's start with the Wolfcamp A wells. If you will look at the solid blue line on the eastern side of our leasehold in the southeast corner, this is the Calamity Jane 22 #1H well. This Wolfcamp A well is our best horizontal well to date and one of the best wells in Reeves County. The well produced 1,966 BOEs per day for its 7-day average. Of that production, 69% is crude oil. The well has a 4,000-foot lateral and was completed with 15 stages using a slick water-based frac fluid to give us some more complex fracture initiation. I will touch on our completion design changes shortly.

Also if you go northeast, about 2 miles from the Calamity Jane well, you will see the Sam Bass well that we reported on last quarter. This was the Wolfcamp A well that was reported as an unstabilized rate due to its water production from what we believe is mostly coming from the Wolfcamp D bench. As you can see with the results of the Calamity Jane well, we are definitely learning more about how to develop the eastern side of the acreage. Also as you can see from the map, we have a few more wells planned for this area, so we are very pleased with what we are learning and the progress we have made so far.

Now if you move slightly north and west from the Calamity Jane well, about 4 miles, you will see our first 3-well pad, a 660-foot well spacing test. These Black Jack wells are all Wolfcamp A bench wells with laterals ranging from 3,900 to 4,200 feet. Each were completed with 15 to 16 stages and used a slick water-based frac fluid for complexity. The Black Jack 16 #1H well had a 7-day rate of 1,395 BOEs per day. The #2H well averaged 1,338 BOEs per day and the 3H well was 1,154 BOEs per day for the same period. Of this production, roughly 76% to 80% is crude oil. We won't know for some time about the optimum development spacing for these reservoirs, but it's important that we begin to gather spacing data, and these wells will do just that. So during the quarter, we brought on 4 new Wolfcamp A bench wells with an average 7-day rate of 1,463 barrels of oil equivalent per day, which exceeds our initial type curve for the area. It's early, but we really like the results we are seeing with our change to a more complex frac design and using slick water to initiate it.

Now let's go over 2 New Venture horizontal wells that we also drilled in Reeves County, 1 in the Third Bone Spring and the other in the Wolfcamp C. First, the Bone Spring well. Staying on Slide #7, just northeast of the 3 Black Jack wells, you will see the Johnny Ringo 9 #2H well. This well is our first attempt at the Third Bone Spring, and we targeted a 3,900-foot lateral. This well was also completed with a 13-stage complex frac design similar to the Calamity Jane and Black Jack wells. The Johnny Ringo's 7-day average rate was 1,251 barrels of oil per day, of which 75% was crude oil. Although most of the attention in Reeves County to date has been focused on the Wolfcamp, we really like the potential in the overpressured section of the Bone Spring. And this well's early results confirm our belief that the resource potential of the Bone Spring is significant.

Let's now move about 7 to 8 miles west, southwest from Johnny Ringo, and you will see our second New Venture test, the Roy Bean 42 #1H. This well targeted a middle section of a 250-foot thick Wolfcamp C bench. It was drilled roughly 4,600 feet laterally and was completed with a 16-stage gel fluid design. This well was completed prior to our change to the complex frac design using slick water. Its average 7-day rate was 361 BOEs per day. Although this well's performance is below our commercial threshold, we remain very optimistic of the resource that the Wolfcamp C offers. We like the productivity of offsetting Wolfcamp C vertical wells in the area as well as a few recent horizontal C wells brought online in the area by other operators. Going forward, we are working to better understand how to optimize picking the targeted landing interval as well as refining our completion design. So all in all, for the period, we tested 6 new horizontal wells in Reeves County that, in aggregate, had an average 7-day rate of over 1,250 BOEs per day.

Let me now speak a little on our completion design we are now using for our horizontal wells in the Permian and how we are looking at it. This will also help you understand somewhat why we made the change on our completion design in the Eagle Ford as well. It's been no secret that we like 2 things in unconventional reservoirs when we think of stimulation design. The first is conductivity and the second is stimulated rock volume. Conductivity allows fluid to flow more easily through the stimulated rock, and the stimulated rock volume maximizes the tank size in these ultra-tight reservoirs. One of the greatest changes we made with our Permian design since last time we talked was trying to increase both conductivity as well as the stimulated rock volume. To increase the conductivity, we have increased our proppant amount and tightened our stage spacing. Our latest wells are pumping roughly 300,000 pounds of proppant per stage, and look for us to continue to vary the amount of proppant we pump per linear foot of lateral. More proppant equates to more conductivity. We have also tightened the distance between stages to about 250 feet. To increase the stimulated rock volume, we are now initiating our fracs with a lower-viscosity slick water fluid. The concept of this is that we will initiate more fractures using slick water than by using gel. We call this our complex frac design. The more fractures we can initiate, the more we can increase our stimulated rock volume and increase the size of the tank. So far, we are seeing some terrific well performances using this method.

In summary, our Reeves County acreage is well positioned in a choice area for horizontal development. Industry data, coupled with the results of our 2014 delineation program, will be key to evaluating and determining the best approach for our lateral development programs in multiple benches for years to come. We have always been excited about the resource potential in this portion of Reeves County, and the early results of our horizontal program is confirming this optimism. Before we move to the Eagle Ford, you will see our recent Wolfcamp A wells production on Slide #8 plotted against our initial type curve, normalized to 4,000-foot lateral length. All 4 recent A wells are outperforming the type curve.

Okay. Let's move on to South Texas. First, I'd like to revisit our Upper Eagle Ford pilot program that I discussed in depth on last quarter's call. I believe you are all familiar with our Upper Eagle Ford concept. That is, where the Eagle Ford is thickest, we believe the Lower Eagle Ford wells are doing a nice job of draining the prolific reservoir in the bottom of the Eagle Ford but not the entire Upper Eagle Ford. As a result, we have been testing how Upper Eagle Ford wells perform as a stand-alone investment. As a reminder, we started this program last year.

Slide #10 shows a locator map of our 4 Upper Eagle Ford pilots. Slide #11 shows the pilots and the landing intervals of the wells. The black are the lower wells and the blue are the upper wells. This morning, I'm going to focus on the third pilot located on the L&E lease and shown on Slide 12. If you recall as of last quarter's call, we only had 3 months of production on this pilot. I will also update you on our fourth or most recent pilot located at Gates Ranch, which is shown on Slide 13. This pilot did not have any results at the time of our last call.

So now let's take a look and review our third pilot, the one on our Central Dimmit L&E lease shown back on Slide 12. Here, our targeted thickness is 160 feet. As you can see, we placed the pilot well, the 31 well, in the center of the targeted yellow area. It is closer to the area in red that we believe has been effectively stimulated by the Lower Eagle Ford wells. But it is also exposing more target rock above it. We do know that fracs are more effective in height growth, above the wellbore than below it, and this location is testing that concept. If you look at the production plot in the upper right, you will see that the upper well is still performing very similar to its 2 Lower Eagle Ford well counterparts. This pilot continues to look very good and targeting the upper well, lower in the column, appears to have paid dividends. Although this is only one pilot and still very early, it appears that establishing an Upper Eagle Ford development program in this area is probable. So look for us to expand the Upper Eagle Ford program here in the future.

Now let's go to the fourth pilot, which is back at Gates Ranch. Pilot #4 is the second type log from the left on Slide 11. It is in East Gates and located just south of Pilot #1. Here, we have drilled 5 Upper Eagle Ford pilot wells. 3 of those wells, the 52, 53 and 54, were placed in the upper target, middle target and the bottom of the target immediately above the red area. These 3 wells also had similar completion designs. Similar to what we have attempted at L&E, we wanted to see if targeting the upper wells lower in the column improve the results of the Upper Eagle Ford well performance. Wells 50 and 51 were also placed in the very upper, however, they each used a different completion technique than the other 3 wells in the pilot.

If you now turn to Slide 13 and look at the production plot in the upper right graph, you will see that the production of the 5 upper wells compared against the average of their lower counterparts. Although this data is extremely early time, the interesting thing about the upper wells is that there is a very direct relationship between where you land the upper wells and their relative performance. The upper well that landed lowest in the column, the 54 well, is performing significantly better than the upper well that landed in the middle of the column, the 53 well. Also, the wells that landed in the very top of the column, the 50, 51 and 52 wells, are the lowest performers. So by intentionally landing lower in the column, it appears that we are seeing better well performance and it does not appear, at this time, they are altering the performance of the lower wells. Keep in mind, this is extremely early data. And as rates and pressures change, we will be able to draw a more reliable conclusion. But the data so far is encouraging, especially since the easternmost part of Gates is also the thinnest on the ranch.

In summary, look for us to expand our Upper Eagle Ford pilot testing by continuing to drill upper wells in Central Dimmit, Briscoe and Gates Ranch. Based on this most recent learning though, the upper wells will now target the lower sections of the upper column rather than just below the Austin Chalk. In an ideal unrisked situation, this program could add hundreds of Upper Eagle Ford locations across these areas as a unique investment to our lower programs. Their EURs are yet to be determined, but with the early performance on the lower landing intervals in the upper column, you can see why we continue to like this play and its potential.

Last and certainly not least, let me update you on our revised Eagle Ford well cost. Our new well cost guidance at Gates Ranch, Briscoe Ranch, L&E, Vivion and Tom Hanks is now estimated to range from $5.5 million to $6 million for a standard 5,000-foot horizontal well. This new estimate is down from our previous $6 million to $6.5 million range. This new well cost is a result of changing the proppant selection and design parameters during the completion phase. We are moving from a ceramic proppant design that has performed extremely well for us over the years in maximizing our conductivity to now a frac design that focuses more on maximizing the stimulated rock volume while still obtaining the necessary conductivity for optimum flow. Our new design, we will achieve -- in our new design, we will achieve this by pumping a sand proppant rather than a ceramic proppant. In doing so, we will also pump much larger volumes of proppant than we have done in the past. On a per well basis, the estimated cost savings are roughly $500,000 or 8% of the total well cost.

We have made this change based on historical well data and the analysis of that data. As most of you know, we have 12 case wells at Gates Ranch spread throughout the entire property where we pump sand and have the data to compare sand wells performance against their direct offsetting wells completed with ceramic. Some of our comparisons are now over a 3- to 4-year time period. As a result of this analysis, we do not anticipate any changes to our EURs as a result of this new design.

That concludes my operational remarks of what has been a very busy but very rewarding quarter. As always, I look forward to future calls to keep you up to date on the activities and results of our South Texas and Permian divisions. And I thank you for your continued interest in our operations. With that, I'll turn the call back to Jim.

James E. Craddock

Thanks, John. Today, we wanted to update you on the significant progress of our horizontal activity in the Delaware Basin. We're extremely pleased with the recent well results and advancement of our program. We anticipate sharing more well results as we test other benches across our Reeves County position in 2014. We also provided a follow-up assessment of our newer Upper Eagle Ford spacing pilots with intriguing new early data. We followed with details of our Lower Eagle Ford well cost guidance reflecting our new completion design changes.

In summary, both of our core areas provide excellent opportunities and catalysts for the future growth of our company. Before we open the call for Q&A, I'd like to acknowledge Rosetta's technical and business support teams for all they've accomplished during the first half of the year. We enter the second half of the year at a fantastic pace, and we plan to continue that momentum going forward.

I'll now turn the call back to the moderator so that we can take your questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of Welles Fitzpatrick of Johnson Rice.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Can you just talk about the difference? So was the 52 well, BVP 52, was that completed like a typical -- like one of your typical lowers would be completed? And can you talk about what the actual difference between that and, say, the BVP 50 was?

John D. Clayton

Yes. Welles, this is John. So you're right. If you're looking at the slide, I think it's 13 in the slide deck, the exact completion design was pumped on the 52 well, the 53 and the 54. We actually pumped sand on the 51 and 52 wells. Some fluid [ph] changes, but the biggest difference was sand.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Okay. And so that was only -- and then can you remind me, were those Lower Eagle Ford wells, were those -- had those been brought on earlier? Or were those completed around the same time?

John D. Clayton

It's a great question. We completed all 11 wells at the same time or, I guess, sequentially before we brought any of them on. So the production all came on about at the same time, and all 11 were completed over probably about a 3- or 4-week period.

Operator

Our next question comes from the line of Michael Rowe from Tudor, Pickering, Holt.

Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just wanted to have one quick question, I guess, on the budget, and then a question on the revised Eagle Ford completion. I guess, as it relates to the budget, how should we think about the capital spending increase relative to the production guidance increase? Are you all baking in much production uplift from the additional $100 million of capital in '14? Or do you think a lot of that rolls into 2015 volumes?

James E. Craddock

Yes, Michael, this is Jim. No, that's the latter. We think that most of the incremental capital will affect 2015. There is essentially little or no effect on 2014. So I guess, just some comments on the increase in capital guidance. We've said for some time that our pace has probably been a little ahead of what we planned as we entered the year. It has to do with a number of things, including drilling wells a little faster than we originally anticipated, and then completion spreads keep up with the rigs. And so as we move through the end of the second quarter and started kind of looking at where we were headed planning-wise, we'd probably run out of capital sometime during the fourth quarter, and it just didn't make any sense to shut down. So really think of the $100 million as being targeting wells that will be completed late in the year, maybe even December, would have essentially no impact on this year's production. But it just didn't seem to serve anybody well by slowing down that much, so that's what's going on. And then Clayton may have some additional comments on CapEx.

John D. Clayton

Yes. Michael, this is Clayton. As Jim said, most of it was -- I think if you just spread out the budget throughout the year, we run a $95 million per month pace. But we accelerated that more to, I think, probably averaged about $125 million per month. So we added. So I think when the '14 is all rolled up, we've guided prior to the increase in capital of having about 90 to 95 wells completed in the Eagle Ford. We've added some late in the year now. So I think when it's all said and done, we'll be closer to 100. But that increase will be very limited production on the annual rate for '14, may have a little impact of the exit rate. But those will be put on at the end of the year. So we did add about 5 to 7 completions at the end of the year. Another point I'd probably make on the operational side, we've been guiding to about 25 horizontal wells in the Permian. And with the increase in capital, we won't be able to complete them by the end of the year. But I think our drilled well count will now be 30 or 31. So we're drilling them a little quicker. This allows us to keep the rigs we've got going throughout the end of the year. And I think when we look back on '14, we'll end up with about 30 or 31 horizontal wells in the Permian drilled. And that's up from about, I think, 25 that we've been guiding to. And then we have done more facilities for 2014 than we've done in the past. I think the way I would look at facilities, for those of you that are external to the company and not internal, if you go back to 2012, we were in full development really only in 2 fields, which was Gates Ranch and then our Karnes Trough area, which was the Klotzman and the Reilly leases. So we only needed central facilities in 2 areas. If you look back just as recently as 2013, we were really only -- we finished developing the Karnes Trough area, and we were still really only developing 2 areas where we needed central facilities, and that was Gates Ranch and Briscoe. If you look at where we are today, we're in full development with multiple wells which require central facilities in Gates Ranch, Briscoe Ranch, L&E, Light Ranch, Tom Hanks. So this really was the year as we moved to full development that we needed to start getting ahead on central facilities investments. And we spent a large portion of the first half of this year not only gearing up for this year but putting in central facilities that will help us in '15. So I think you had one more question.

Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Right. That's really helpful. And I guess, the last question is just as it relates to the change in completion design in the Eagle Ford. So I guess, can you all quantify the exact increase in proppant volume as you're switching from ceramic to white sand? I think you all have been using around 4 million pounds per well over the past couple of years. And so I was wondering if one, if that was correct; and two, kind of how the total volume on a per well basis should change going forward.

John D. Clayton

Yes. I'll use some per stage numbers here. So if our normal job is, let's say, 275,000 pounds per stage, we've got some sensitivities run that actually can get us up to 0.5 million pounds per stage, and then we step it up from 275,000 on about 100,000 pound increments. The one thing I'll point out though is the data that we looked at that compared our 12 wells with historical sand to their offsetting ceramic wells, now that we've got 3 to 4 years of data, we've seen cycling in the reservoirs with shut-ins and frac-ing offset wells. That's still based on the 275,000 pound design. If you do the straight math, and I'm going to go through some numbers here. But Toni can probably walk you guys through them later. If you strictly kept the proppant amount the same at about 275,000 pounds per well and went from ceramic to sand, we're saving close to $900,000 per well. But our plans going forward are to move to sand, but then as you mentioned, increase the amount of proppant because we want to maximize the conductivity and try to get somewhere higher than what just a normal sand conversion would've done, and that's where we added back in about $400,000 per well cost, only resulting in a $0.5 million per well savings. So I hope that answered your question.

Operator

Our next question comes from the line of Chris Stevens of KeyBanc.

Chris Stevens - KeyBanc Capital Markets Inc., Research Division

I know it's pretty early, but is there any color you can provide on what the expectations are for improvements in rate of return or in EURs or first year of production in the Wolfcamp with your new slick water completion design and what the well cost differences for slick water versus the gel?

John D. Clayton

Yes, Chris. This is John. I'll maybe start backwards on your last question first. So I think we've been guiding from $8 million to $9 million, maybe with a midpoint of $8.5 million for our 5,000-foot lateral in the Permian. Once we start pumping more sand, which we've done recently on these, we do get -- we will have an increase in cost just because we're pumping more volume of sand. If you look at kind of how we've acted in the past, we've only got a handful of wells underneath our belt right now. I think that production plot that was showing the well results on the test -- I forgot what slide that was on. Toni is going through it now. Slide #8, I mean, that's our population of wells that we've operated. We'll probably come out with a new well cost estimate. I don't anticipating it being outside of the range that were given, which is up to $9 million. But if we keep increasing the amount of proppant to increase conductivity, we will see an increase in well costs. But then I will point out, we haven't increased our type curve either. So let us get some more data. I think I would probably say let us get 2014 behind us. We'll be doubling this well count here over the next 6 or 7 months as far as data. But as you pointed out, more sand is going to equate to more cost. But we're starting to realize it on the EUR front as well.

James E. Craddock

Yes. And I guess, I would just add to that. I think we've said this to you before, but the other piece to the equation is moving from delineation to development can have a very substantial effect on the average well cost. And when we did that at Gates several years ago, we saw well cost drop by $0.5 million or more. And so that's the other part we want to see is what that looks like once we do several more of these multiwell pad tests and see what development costs look like as we go forward, too.

Operator

Our next question comes from the line of Irene Haas of Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Really fantastic batch of wells coming in this quarter. My question for your is the 6 or so wells. Can you tell me a little bit about the timing as to when they come on, like Calamity Jane and the batch of Black Jack wells and Johnny Ringo? Just sort of if you can tell me which month, it would be helpful just to see how they impact the third quarter. Then second question I have is your Third Bone well looks great. Does it extend across your entire acreage footprint?

John D. Clayton

Irene, this is John. I'll apologize upfront when I go through the timing of these wells. But the Wolfcamp C well, which was our poorest performer, came on first. It came on very early in the quarter. The Third Bone Spring well, which is a very good well, it actually didn't even come on until July, which was outside of the quarter. And I think in Jim's script, he mentioned July. But we had a 7-day test on it, so we provided that. The other wells came on at the second half of the second quarter, so they were brought on towards the tail end of the second quarter. So as you pointed out, these will have a much larger impact, even with decline in our third quarter results for Permian, than they did in the second. But it was unfortunate we brought on the poorest-performing well and had a full quarter's production on it, and one of our better wells didn't even come on until July. But we reported what we had at the time.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Got you. And then the Third Bone, how far does it really go towards the south? Is it coming from [indiscernible] from the northeast?

John D. Clayton

Most -- you're right. So most of the activity in this part of the Delaware Basin in the Bone Spring is north of our acreage across the river. But as we push it -- I mean, we -- I won't be able to tell you exactly how we have it all mapped just because we've spent a lot of money to map it this way. But we're pretty pleased with its extent over our majority of our acreage position. So with that test there, I mean, look for us now to not drill the direct offset to us, kind of do what we're doing in the Wolfcamp A. Look for us to move pretty far from it and drill another test and see if we can keep delineating it. But we're very pleased with it. And as I mentioned in my script portion of it, this is the overpressured part of the Bone Spring, which is a pretty large interval at the base of the Bone Spring. And some people call it Third Bone Spring, as you know, but it's got a pretty large regional extent. And we like where we sit with our acreage.

Operator

Our next question comes from the line of Neal Dingmann from SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Somebody else said it, I know it's early in the Delaware, but just a question over there as far as how you would tackle as far as spacing or going after some multibench pads. Is that something that is already in the cards right now? Or how are you looking at that?

John D. Clayton

Yes. Neal, this is Clayton again. But it's a great question. We've had multiple operators and we haven't done it yet. But we've seen multiple operators either drill at least 3 benches from a single pad or permit 3 benches from a single pad. And that'll help us understand this. It's an interesting phenomenon. So I'll give you a real isolated deal. If you go to Slide 7 and you look at where our Calamity Jane well is, for instance, you'll see that we've got a well directly north of that well, and we have a well that's about 2 miles east of that well. And we plan on drilling those wells and completing those here in a pretty timely manner. If we can prove up and triangulate between the performance of those 3 wells, then that'll set us up for adjusting the Wolfcamp A bench. I think it's 21 wells, if I counted it right before. Now we're using 6,060-foot spacing. And as you know, in the Eagle Ford, we've spent a couple of years trying to learn what the right spacing is, and we're still dealing with that. But I think the way this play will evolve is once we can triangulate a tight band of distribution by reservoir, we'll go in and we'll go into development mode on it. There's enough separation between Bone Spring, Wolfcamp A, B and C benches that although we'd like to see the well performance in all 4 of those benches underlying the acreage position, I think we'll be able to stay out of it just because it's about a 1,000-foot column. And so we ought to be able to develop one and deplete that and not interfere with the things below it. But I think we're pretty pleased with the amount of development that's occurring here now, especially outside of the Wolfcamp A.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then just lastly, John, moving over to the Eagle Ford, you mentioned in your earlier remarks about the Upper Eagle Ford. I'm just kind of wondering the prospect [indiscernible] for that and the overall. Or I guess, what I'm asking is how many additional locations are you assuming now that would add? Or I guess, if it's highly successful in nearly all of it, how many more locations could that add to your play?

John D. Clayton

Yes. So I'm going to -- I'll give you my Safe Harbor statement, which is I'll just tell you how I feel about this. I think we've said we like it where it's the thickest. And so that would include our Gates Ranch, Briscoe, L&E and Vivion lease. And then if we look even more detail, as you look at the, let's say, gassier areas as you come on the southern part of Gates, that probably needs a little more testing. We had a pilot on the very southern tip, and those wells didn't perform as well as the changes we've made on the eastern tip. So if you take the northern half of Gates, split it in half and take the northern half, I believe internally we think that's got quite a bit of potential. And then if you take all of Briscoe, all of L&E and all of Vivion, we believe those assets also have potential across the entire asset base. As you move east to Light Ranch, we don't see it again over there, so I would exclude Light Ranch and I would exclude the southern part of Gates. But all those other ones, that's the size of the prize that we're looking at.

Operator

Our next question comes from the line of Brian Gamble of Simmons & Company.

Brian D. Gamble - Simmons & Company International, Research Division

Just a couple of quick ones. The Third Bone Spring test that's coming up this quarter, where on the acreage are you going with that? Are you stepping pretty far away from Ringo? Or are you staying in relatively close proximity?

John D. Clayton

Yes. Brian, this is John. All of our wells will have at least some step-out to them. The only time we go in, at least in this phase of delineation, and not drill a direct offset, we're trying to prove up a different geologic concept by getting some distance between the 2. If you see us drill a direct offset, we're probably anticipating homogeneous reservoir and we want to start getting data on spacing. So the Third Bone answers that question. But really on a macro sense, anytime we're drilling a well, we're trying to learn something through the delineation, unless it's a spacing test.

Brian D. Gamble - Simmons & Company International, Research Division

So how far away from that one are you doing it?

John D. Clayton

More than a mile.

Brian D. Gamble - Simmons & Company International, Research Division

More than a mile, okay. And then just wanted to follow up on the well cost question from before, just to clarify. The Wolfcamp A well that you drilled this quarter, what did those end up costing you? Because it did have the shorter laterals, and I would assume -- you already said you moved to the new frac, so higher frac content. What were those -- what did those end up costing you?

John D. Clayton

Yes. I mean, I would look at -- and they're a little shorter laterals, but I would look at with, I'll call it, a single well pad drilling anytime we drill a Wolfcamp A or B well. And I'm going to hold the C out for now. But anytime we drill a Wolfcamp A or B well or a Third Bone Spring well, we'll still be from an overall standpoint in that $8 million to $9 million range. The Wolfcamp C, and we've got one data point on that, it drilled a lot different. It's a much harder rock. It was hard on bits. It took a long time to drill. And it had about a 25% higher frac gradient than our upper wells. So those wells right now are probably going to be higher cost. So we've got some more work to do on understanding what's going on in that reservoir. But if you take the Bone Spring well down to the Wolfcamp B, we'll stay in that $8 million to $9 million range at least for modeling standpoint. And then once we get a little more data behind us, we'll be able to update that.

Operator

Our next question comes from the line of Will Green from Stephens.

Will Green - Stephens Inc., Research Division

Great results on the Calamity Jane. You guys talked about how your increasing the proppant. I wonder if you could talk about how the drilling complete looked any different from the rest of the results you guys announced. Besides just the spacing of the Black Jacks, anything in the Calamity Jane that was drastically different than what you're doing elsewhere?

John D. Clayton

Yes. Will, this is Clayton again. As far as the drilling and all, they drill and treated the same. The one thing I'll point out about the eastern side of our acreage position, there's a subtle geologic nose that comes in from the east. And the reason we originally liked it and still do, and when we drilled the Sam Bass well, which had quite lower performance than the Calamity Jane, is anytime you have a nose that comes in, it gives you some flexure in the reservoir, which the way we look at that should give us increased productivity because the rock should be a little more fractured naturally as opposed to us fracturing it. So when we drilled the original Sam Bass well, I think what we learned on that, and we pumped the gel on that one, we learned that we got into a lot more water than we had anticipated, and we believe the majority of that water is coming further down from the Wolfcamp D. Now did we frac into that all the way to the D? I don't think so. But if it is naturally fractured, if you put a large frac on it, odds are that, that frac might hook up to a fracture network that brings up the water. So we went to the Calamity Jane, which is still in this kind of subtle nose area. As we come down off that nose, we changed the frac design a little bit, more complex, and we got better results. So it didn't drill any different. But geologically, as you move to the eastern side, there is a subtle nose there that we really like the opportunity for that to create a little more natural fractures in the reservoir. And I think we saw that on the Calamity Jane. If you also look at that production plot, and it's very, very early, I mean, it's just a few days into it, the production profile of that is pretty good. And so if you extrapolate that out to 30 days, it's going to have a great 30-day rate as well if it keeps on the same profile. So I think we might be in an area that's more naturally fractured. Drilling was the same.

Will Green - Stephens Inc., Research Division

Got you. And then the other one I wanted to touch on is the Roy Bean. Obviously, testing at the Wolfcamp C is a deeper zone, but you guys also used a gel frac. First off, what's your initial thought on what's going on there? Is it just the geology is maybe a little bit more challenging there? Is it possibly the gel frac? And then beyond that, when do you guys plan -- if you plan to test one, when do you guys plan to test another Wolfcamp C well?

John D. Clayton

Yes. So a little bit of the Roy Bean. We did pump a gel frac on that. And I think we strongly believe now these more slick water-initiated complex fracs are a much better way to go. I will say, though, that based on the way that well drilled, I don't think it is all frac design. I think we would have gotten a better result if we pumped a slick water frac. But when we drilled that well, the landing interval that we targeted, which was about in the middle of the C bench, was extremely hard. So we saw it from a drilling standpoint. And then when we went to frac that well, we normally frac a well with -- and I'll be in the ballpark here, but we normally frac a well with about 0.8 psi per foot frac gradient. And that well treated over 1. So there's no doubt there's a hard streak that I believe we drilled in. So we kind of know what we'll do different on the completion. Our technical guys now are looking at what's the better landing intervals in that zone to give us better conduit. The reason we chose that area, and it's the same reason we're still optimistic about it, we've done some testing on vertical wells and we've got vertical well results that produce out of the Wolfcamp C, and we like what we're seeing from those. And then we're in a ZIP code here with some pretty good operators. And just a couple of miles from that well is a Wolfcamp C well that was brought on not too long ago by an offset operator. And it's a much better well. And if you put the 2 logs down side-by-side to each other on the offset vertical wells, you can't tell them apart. So I think it's more where you land as opposed to a larger geographic area.

Operator

Our next question comes from the line of Joe Magner from Macquarie.

Joseph Patrick Magner - Macquarie Research

Just going back to the Upper Eagle Ford performance, while it hasn't altered the profile of the Lower Eagle Ford wells in those particular areas, how long do you think it could take for you to know whether you're seeing great acceleration of Lower Eagle Ford reserves versus unlocking incremental reserves potential and how much?

John D. Clayton

It's a great question, Joe. I'm glad you asked it because we normally wouldn't put production data out there until we had like a year's worth of production. But it's such an important play on what we're trying to do and what we're seeing, we've put production out that's very early time. So we take -- on that production plot that had the 11 wells in the Upper Eagle Ford at East Gates, we kind of discount the first 50 days. I mean, it's wells flowing back. You're probably getting flush production on what you've stimulated. And then we started looking at the longer-term performance. I think we drew conclusions on our other pilots at the 9- to 10-month range. So these are at month #2, the L&E is at month #6. We'll probably update both of these again next quarter. But I like to see more data. 9 months is cutting it pretty short. These wells have pretty good payouts. So we can maybe kind of accelerate and understand if we are seeing some interference. But I like to see at least 9 months. And anything more than that just brings more comfort into it. But I'll emphasize the point we're showing you data that's extremely early, and we're not drawing any firm conclusions on it. We just like where the data is headed and what we're seeing at this early point.

Joseph Patrick Magner - Macquarie Research

Okay, that's helpful. And then back to the sand versus ceramic design change in the Eagle Ford. Are you switching now to 100% sand? Or is this going to be a phased switch? I just want to get a hand on where you were previously. Outside of the tests that you were evaluating and comparing sand versus ceramic, were you using 100% ceramic? And are you going to go to 100% sand? I'm sorry if you've said that already, I just missed it.

John D. Clayton

No. So as we look at it right now, we're going to go to 100% sand and we're going to increase the sand amount to try to catch up to the amount of conductivity that the ceramic gave us. So we're going to go to 100% sand. Now there's some other plays that we're looking at that tail in with some stuff and different ways to do it. But it'll be a while before we change anything. We want to get out data set on increased sand proppant, and we're going to be 100% sand.

Operator

Ladies and gentlemen, that is all we have for question-and-answer for today. I would like to turn the call back over to Jim Craddock for closing remarks.

James E. Craddock

Great. Well, thanks for joining us today. We look forward to visiting with you in November to update you on third quarter results. Have a good day.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This concludes your program. You may now disconnect. Everyone have a great day.

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Source: Rosetta Resources' (ROSE) CEO James Craddock on Q2 2014 Results - Earnings Call Transcript

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