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Rosetta Resources (NASDAQ:ROSE)

Q3 2012 Earnings Call

November 08, 2012 11:00 am ET

Executives

Don O. McCormack - Vice President and Treasurer

Randy L. Limbacher - Chairman, Chief Executive Officer and President

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

James E. Craddock - Senior Vice President of Drilling & Production Operations

John D. Clayton - Senior Vice President of Asset Development

Analysts

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

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

Pearce W. Hammond - Simmons & Company International, Research Division

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

Brian M. Corales - Howard Weil Incorporated, Research Division

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

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

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Dan McSpirit - BMO Capital Markets U.S.

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

Joseph Patrick Magner - Macquarie Research

Operator

Good morning. Welcome to Rosetta Resources Third Quarter 2012 Conference Call. Joining us this morning from Rosetta are the following individuals: Randy L. Limbacher, Chairman, President and Chief Executive Officer; John E. Hagale, Executive Vice President and Chief Financial Officer; John G. Clayton, Senior Vice President of Asset Development; Jim E. Craddock, Senior Vice President of Drilling and Production Operations; and Don O. McCormack, Vice President and Treasurer.

Today's conference is being recorded. [Operator Instructions] If you are not able to participate in the conference call, an audio replay will be available from November 8, 2012, 2:00 p.m. Central, through November 15, 2012, 11:59 p.m. Central by dialing (855) 859-2056 or for international, (404) 537-3406 and entering conference code 40307116. 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 our website and select Events. At this time, I'd like to turn the call over to Don McCormack. Mr. McCormack, you may begin your conference.

Don O. McCormack

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

With that disclaimer, let me review the agenda for the call. Randy Limbacher will open with remarks about our overall performance for the quarter and the first 9 months of the year. Next, John Hagale will provide a brief financial review, followed by Jim Craddock, who will discuss operating results. Finally, John Clayton will update you on our asset development activities. Randy will then open the lines for Q&A.

Let me now turn the call over to Randy.

Randy L. Limbacher

Thanks, Don, and good morning to everyone. I'd like to take this opportunity to officially welcome Don McCormack to our quarterly conference calls. I know that many of you have met or spoken with him already. Don joined us late in August as Vice President and Treasurer. One of his responsibilities is oversight of the investor relations function reporting to John Hagale. Don has an extensive background in financial and management roles in the exploration and production industry, and we're pleased to have him as a member of our team.

With the completion of the first 9 months of 2012, we enter the fourth quarter on target to meet the expectations of the marketplace and deliver another year of solid financial and operational performance. This quarter reflects the culmination of numerous drilling and operational activities that are fulfilling our promise of strong second half production results. For example, we achieved our best of our total daily production with a 45% increase in year-over-year production. We set all-time high levels for quarterly liquids production with higher valued liquids products now representing 60% of our total production and more than 80% of our sales. And we recorded almost a 70% increase in daily volumes from our Eagle Ford Shale properties year-over-year.

Moreover, the continued shift in our commodity mix to higher valued liquids products combined with increasing volumes is enhancing revenues and profitability. As we finish 2012, we will rank among the top of our peer group in terms of growth, a position that we believe we can maintain well into the future.

Over the last 9 months, we have successfully diversified our producing base into 4 different areas of one of the most active and economically attractive energy basins in the United States today. At our original discovery at Gates Ranch in the Eagle Ford Shale, our down-spaced wells are performing per our expectations. Approximately 80% of our identified well locations in this prolific area have yet to be drilled. Production is now underway in the Karnes Trough area where 8 wells are now online. Drilling and completion activities are also in progress on leases in Central Dimmit County and Briscoe Ranch. Jim Craddock and John Clayton will give you specific details about quarterly operational results.

These include a couple of firsts. The completion of our first 3-well pad at Briscoe Ranch and the first successful test on our third lease in Central Dimmit County. Suffice it to say, we could not be more pleased with our drilling results thus far and this gives us added confidence in developing our capital plans for 2013. As you read in our press release, we are adding some capital to our 2012 program, including increasing the range from $20 million to $40 million over our planned $640 million budget. During the quarter, we identified several activities related mostly to new ventures and our continuing Eagle Ford success that will increase our capital needs. And Jim Craddock will discuss this later in more detail.

We're still fine-tuning our 2013 capital budget for approval by our board in December. However, we've already taken several steps that will put us ahead of the game in the new year. These include drilling a backlog of wells for completion, adding facilities capacity and at the same time, taking a fresh look at our 2014 marketing commitments. We will enter the year with a significant portion of our production hedged.

Our current plans for 2013 assume a run rate of 60-well completions per year with approximately 10% of capital funds allocated to new ventures. Moreover, assuming a similar activity level to that of this year, we would expect to deliver around 30% year-over-year production growth next year at, again, competitive industry finding and development costs.

As we told you last quarter, we're in good shape to record another impressive reserve replacement ratio for the year, but a preliminary estimate of proved reserve additions to annual production of at least 450%.

In closing, this is one of those quarters where the results speak for themselves. From my perspective in terms of almost every measure that defines success in our industry, we achieved a level of performance that confirms the strength of our business strategy and demonstrates our capability to execute that plan to build greater value for our investors. As always we thank you for your continued support, and now let me turn the call over to John Hagale.

John E. Hagale

Thanks, Randy. As a reminder to our audience, all of the information that I am reviewing is contained in our 10-Q, as well as our press release. Both of these were filed with the SEC and are available on our website.

Net income for the third quarter was $17.7 million or $0.33 per diluted share versus a net income of $31.9 million or $0.61 per diluted share in the same period of 2011. Adjusted non-GAAP net income was $40.3 million, or $0.76 per diluted share, excluding an unrealized loss on derivatives of $35.4 million or $22.6 million after-tax. Revenues for the third quarter were $122.8 million compared to $101.3 million for the same period of 2011. Revenues, excluding our unrealized derivative activities, were $158.2 million compared to $103.2 million for the same period a year ago. Of that amount, 83% was generated from the sale of liquids when you exclude the effects of realized -- including the effects of realized derivatives, as compared to 68% a year ago.

Operating costs continue to improve on a per-unit basis versus the prior quarter. Our total lease operating expense is down 7% on a unit basis. That number, direct LOE, workovers, insurance and ad valorem tax that, like I say, is down 7%. The improvement is a result of continued success in the Eagle Ford and the impact of the divestiture of our noncore natural gas properties.

Our per unit Treating & Transportation expense also declined by 9% as we began producing from the Karnes Trough area that realizes lower T&T costs. However, as you can see from the guidance, we expect that number to tick back up in the fourth quarter on Treating & Transportation.

As of November 7, we had $170 million outstanding with $455 million available for borrowing under our credit facility. As Randy mentioned, we continue to proactively hedge our production. In October, we entered into additional derivative positions for both natural gas and natural gas liquids production, including the ethane component of the NGL barrel, which we had previously excluded. So for 2013 and 2014, the NGL hedges are full barrel swaps including ethane.

Let me close with some color around guidance. In the press release, we have included a summary of the fourth quarter expense guidance that is also shown on Slide 5. Overall, our unit costs for the fourth quarter are trending down. As we near the end of the year, there are fewer assumptions and more firm data.

That's all I have for now. Let me turn the call over to Jim Craddock for the operational comments.

James E. Craddock

Thanks, John, and good morning, everyone. I'll go over third quarter operational performance and touch on fourth quarter guidance to finish out the year. The quarter included a milestone event for our company as we celebrate the completion of our 100th producing well in the Eagle Ford. In addition, we achieved all-time highs in both total production and liquids production and successfully tested another Eagle Ford development area outside of Gates Ranch.

During the quarter, capital expenditures were $188.4 million for a total of $492.5 million spent through the 9 months. We drilled 25 gross Eagle Ford wells and completed 16. Our average daily production for the quarter was a record 37,100 barrels of oil equivalent per day. Production was up 45% from the prior year and up 11% versus the second quarter. The year-over-year and sequential increases are a result of our continued growth in the Eagle Ford trend.

As I discussed on the second quarter call, we expect production growth to be back-end loaded in the second half of the year and we'll likely see increases through the remainder of the year. Liquids production continues to be a leading contributor to our overall growth story and averaged a record 22,300 barrels per day for the quarter, constituting about 60% of total production using a 6:1 equivalency ratio.

For the month of October, total production averaged 41,200 barrels of oil equivalent per day, which equates to an 11% increase versus the third quarter average rate. Also, October liquids constitute about 64% of production.

Please refer to Slide 7 in our presentation deck, which shows Rosetta's historical quarterly production profile and the significant contribution from our outstanding Eagle Ford growth over the last 10 consecutive quarters. In the Eagle Ford, we ran 3 rigs at Gates Ranch, 1 rig in the Karnes Trough area and 1 rig at Briscoe Ranch during the quarter. As I mentioned earlier, we completed 16 wells in the third quarter, which brings our total for the year to 43 completions, which is on pace with the full year when compared to our previous guidance of about 60 completions.

At Briscoe Ranch, we completed our first 3-well pad and are seeing production results consistent with the previously released type curve for that area. At the end of the third quarter, 28 drilled wells were awaiting completion, 24 of which were drilled during the third quarter. Rosetta plans to complete 15 to 20 Eagle Ford wells during the fourth quarter and continue to operate 5 rigs in the play, including 2 to 3 rigs at Gates Ranch. At year-end, we will have 35 to 40 Eagle Ford wells drilled and awaiting completion consistent with our approach of maintaining sufficient distance between the drilling rigs and the completion spreads.

Direct LOE averaged $2.77 per Boe for the third quarter. That's up 45% from the quarter a year ago and up about 11% sequentially, a result of the increased support required for the implementation of multiple development programs in the Eagle Ford, as well as increased oil handling and the overall growth in the number of producing facilities. Through the first 9 months of 2012, direct LOE averaged $2.39 per Boe, down 21% from the first 9 months of 2011. For the remainder of 2012, we anticipate direct LOE on a unit basis to trend downward. More on that in a moment.

As Randy mentioned, we are updating our full year capital guidance to range from $660 million to $680 million compared to the original budget of $640 million. The incremental $20 million to $40 million is dependent on the timing of several activities. These projects include the drilling of 2 exploratory wells that are not part of the Eagle Ford program, several acquisitions both within and outside of the Eagle Ford Shale. Also incorporated is the cost of facilities construction to support our expected 2013 Eagle Ford expansion.

We continue to stay ahead of facility requirements to avoid any production interruptions and facility-related delays. In addition, incremental capital includes Rosetta's share of cost for 12 outside-operated Eagle Ford wells, plan to drill in the fourth quarter, as well as 2012 costs associated with the upcoming move of the corporate office in 2013.

Now let's turn to where we expect to land in the fourth quarter. Rather than providing a range of quarterly volumes, let me give you a couple of bookends for the quarter. October production is coming in at 41,200 barrels of oil equivalent per day. At the other end of the quarter, we expect to exit 2012 at the high end of the previously provided range of 39,000 to 44,000 Boe per day with liquids constituting about 62% of total production. On the expense side, direct LOE is expected to average $2.40 to $2.50 per Boe for the fourth quarter of 2012.

I'll now turn it over to John Clayton.

John D. Clayton

Thanks, Jim, and good morning, everyone. This morning, I would like to update you on our asset development activities during the third quarter. Our primary accomplishments include, first, the continued favorable down-spacing performance of our Gates Ranch asset; and secondly, our exploration success on our westernmost Central Dimmit track. On last quarter's call, we announced that Gates Ranch would be developed on 55-acre spacing or roughly 475 feet between lateral wellbores. We continue to monitor the well performance in the down-spaced areas, utilizing rate time analysis and reservoir simulation, and we evaluate drainage areas and recovery factors. We now have 3 areas of Gates Ranch that have wells spaced at 55 acres or less and none of them have shown indications of well performance that are different than our offset wells spaced on the original 100-acre spacing.

To illustrate this point at a high level, let me ask you to turn to Slide 9 in the presentation. Here, you will see relative data on area where we have our largest population of continuous wells that are spaced on 55 acres. This area consists of 9 wells, all drilled and completed 475 feet apart, which is 55-acres, taking into account 5,000-foot laterals. To the left, you can see that these wells are centrally located within Gates Ranch. To the right, we have plotted cumulative production in Boe versus time. 9 wells spaced on 55 acres are colored in red while similar offsetting wells that were drilled earlier in our development and therefore have more production history are plotted in light gray.

As you can see, we are seeing very similar production profiles at this point in time when compared to 100-acre spaced wells that have been on production now for up to 2.5 years. This is just one of the many technical data sets that our technical staffs look at frequently in determining drainage patterns and well spacing. And needless to say, we are very pleased with the well performance on 55 acres.

Now let's turn our attention to northeast of Gates Ranch to our Central Dimmit County asset, which is shown on Slide 10. As you know, this asset is comprised of 3 tracks, totaling roughly 8,100 net acres located in the oil window. Rosetta operates all 3 tracks with a 100% working interest. Our most recent exploratory well, the Lasseter & Eppright #1 is located on the westernmost track. This exploratory well was completed with a 5,400-foot lateral and 15 frac stages and brought online September 23 of this year. The well tested at a gross 7-day stabilized rate of 667 barrels per day of oil, 1.8 million cubic feet per day of residue gas, and 262 barrels per day of natural gas liquids for total equivalent daily rate of 1,228 Boes, which 76% is liquid. In total, as of the third quarter, we have an estimated 122 remaining wells to complete on the Central Dimmit County asset.

As we gain additional data with a few more wells and data points, we'll be forthcoming to you with our type curves for this area, but needless today, we are very pleased with the results to date. One last note on our nonoperated properties before I turn it back to Randy. As we have mentioned in the past, Rosetta owns a small nonoperated working interest on a property in Western Webb County. That to us, this equates to about 3,000 acres. Although we had no activity to the first part of this year, the operator plans to drill 2 fixed well pads in the fourth quarter and we have elected to participate with our working interest. The pad drilling technology continues to evolve and different well spacings are being tested. We're very excited to be part of this learning. Needless to say, we will be closely monitoring the operations, as well as the associated well performance.

Finally, as always, Jim and I would like to thank our technical groups for their contributions to the continued success of our company. They've truly done an outstanding job. With that, I'll turn the call back to Randy.

Randy L. Limbacher

Thanks, John. I'm sure that our comments this morning have generated some questions on your part. So now we'll turn the call back to the moderator so that we can answer those questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Jeff Hayden from KLR.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

Just I wanted a little more color on the additional $20 million or $40 million for CapEx. Wondering if you give a kind of breakout for us how much could it potentially cost you for those couple of exploratory wells, what are you kind of looking at for that land budget? And what are you guys kind of modeling for those 12 non-op wells in the Eagle Ford?

James E. Craddock

Jeff, this is Jim Craddock. I don't know that I've got all the details in front of me on all of those, but I can tell you a bit. In terms of the non-op wells, I mean, that's a fairly small portion of that. I think it's around $3 million. As John said, we have a fairly small working interest there. And yes, so I don't have a detailed breakout of the drilling and the lease cost. I would remind you that some of that lease acquisition effort is going to be focused on Eagle Ford and lease costs are pretty high there with the maturity of the play. So for not a lot of acreage, you do -- you have to spend a bit of money there.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

Okay. And I understood if you guys don't want to provide color on this one, but the 2 exploratory wells, are those horizontal or vertical tests?

Randy L. Limbacher

Yes. We appreciate your understanding.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

Somehow I thought that was going to be the answer. One last one and I'll jump off. When you guys look at the 2012 growth rate of kind of above 30%, how should we think about kind of the liquids split for 2013?

James E. Craddock

Jeff, Jim again. We're still working the budget. We have yet to go through the process with our board of getting that budget approved so we're not going to probably provide a lot of detail. But I think you can think of it to be somewhat similar to what we're currently seeing in the third quarter and going forward into the fourth quarter. We're sort of guiding toward that 60% to 62% range.

Randy L. Limbacher

What we tell folks is if we were drilling -- if we're just drilling at Gates Ranch, it would probably be in the 55% range and as you add -- so it just depends on how many of these wells we're going to add in the Briscoe and Central Dimmit areas to whether it's closer to 60% or closer to the 55% range.

Operator

And our next question comes from the line of Welles Fitzpatrick from Johnson Rice.

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

You guys have talked in the past about being roughly flat CapEx-wise year-over-year. Does that still hold true with the new $660 million to $680 million guidance looking forward to '13?

James E. Craddock

No Welles, when we're talking about roughly flat, we're talking about activity levels although you could infer some capital out of that. But yes, we're sitting here today with the range that we're giving you. We're still working with the board where we're going to ultimately land capital dollars for next year. But the activity levels are going to be about the same. And so we're -- that's about all color I'd give you, but...

Randy L. Limbacher

Yes, I mean, we'll get to December and we'll have our budget approved by then and we'll be able to give you -- we're trying to give you just a little bit of direction and where we were headed with that thing. I think the biggest variable is going to be the -- what we've said is we'll look to 5% to 10% of our capital being in new ventures and wanting to test a couple of different concepts per year as part of our ongoing strategy. So I think within that, the variability in that range is more around how much land you end up adding as part of that process.

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

Okay, and one more. As far as the leasing is concerned, any chance you guys will give us an idea as how spread out that is? I mean are you guys really chasing 1 play with the new acreage buys now or is it 3 or 4?

John D. Clayton

Well this is Clayton. I think if you kind of go back and look at the process, we've stated we're trying to attempt. We said, "You know, at any given one time, we'd like to be testing 1 or 2 plays in the new ventures front." So I don't think you'll see us testing up to 4 at a time. We're not going to comment on the wells we're drilling. However, I think it's fair to say that we're testing 2 plays right now outside of the Eagle Ford. And I'll leave it with that, but that's pretty consistent with kind of how we've approached this before, up to 10% of our capital allocated towards new ventures and 1 to 2 plays being tested at any given time.

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

And when you say 2 new plays outside of the Eagle Ford, does that -- would that -- when you say outside of the Eagle Ford, we now, therefore, exclude the Pearsall or could that be in the plans?

Randy L. Limbacher

Thanks for understanding. I would just -- we're not trying to be cute on this. The reason we mentioned -- we're not trying to play this so we've got this stealth thing or that stealth thing. What we're trying to do is give you some color around the variance in the capital that we had in the fourth quarter. So we thought it important to explain that and give you a sense that the change is a result of incremental activity on the new ventures side and it has nothing to do with cost structure related to the Eagle Ford. I think the operating results speak for themselves that we're delivering very nicely in line with the plans and the cost structure we laid out with Eagle Ford. That's really what we're trying to do with that.

John D. Clayton

I will add, Welles, that -- I mean, there is a lot of activity going on in South Texas right now, targeting the Pearsall with our lease position throughout the play. I mean, I think you can make an assumption that we're following the activity real closely.

Operator

And our next question comes from the line of Pearce Hammond from Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

Randy, in the A and D markets, specifically in the Eagle Ford, there are a lot of interesting packages, land packages on the market right now or is it a lot of it sort of overpriced more marginal acreage?

Randy L. Limbacher

I'll let John add to it. I mean there is a lot for sale out there right now. And rather than being specific, I would say, yes, it's of varying quality from things that are interesting all the way to things that, to us, don't look very attractive at all. But I know that's not very helpful to you, but John?

John D. Clayton

Yes, Pearce, what I would add is there is quite a bit of activity on land coming on the market now and so you have to ask yourself, "Why is that?" As you know, in South Texas, the primary terms on these leases are 3 years. The play started getting, I think, from a lease perspective, pretty hot back in 2009, 2010. So unless that acreage has been drilled and in a continuous drilling or an HBP mode, it either reverts back to the mineral owner or they put it on the market to get it drilled. That's why you're seeing the activity. If you look at -- we're spending our cash flow right now and the majority of that or 90% is being pumped into the assets we have in Eagle Ford. We've got some pretty high-quality assets relative to what's coming on the market right now and to take capital off of that to put into some that maybe are more fringy, it's probably not prudent for us especially some of the larger packages that require continuous drilling.

Pearce W. Hammond - Simmons & Company International, Research Division

And my follow-up would be given the number of packages that you mentioned that are out there vary in quality, this is a tough question, but do you think it's sort of migrating from a seller's market to a buyer's market?

John D. Clayton

These wells take, I think, we're spending $7 million to $8 million a well right now. And when you start looking at some of the drilling commitments to keep those packages, especially some of the larger packages that are on the market right now, it is pretty tough to commit that much capital to assets you don't feel can compete with your own. So I wouldn't say it's a buyer's market right now. I think maybe the mineral owners are the ones that are in the driver seat right now because whoever buys them is going to have to drill them.

Randy L. Limbacher

Yes, I would just add it's like anything else. It's all about the quality of the asset you're going to pick up. So I think if the bottom end of that market, the things that are less economically attractive, that's going to be in favor of the buyer. And on the higher end of the market, the more attractive packages, the things with the better economics, they're going to still continue to trade for a premium because they're going to attract capital. And I think if you're looking for some direction from us, we would tend to want to be more interested in those things that are at the higher quality end that regardless of the pricing environment you end up in that they would compete nicely for capital within our capital allocation schemes, if you will. So I think that gives you a little direction of what we may and may not be looking at.

Operator

And our next question comes from the line of Irene Haas from Wunderlich.

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

Question is your 2 exploration wells, are they located in South Texas?

John D. Clayton

This is John, Irene. I appreciate the interest in them. I'll reiterate what Randy said. We're really not trying to be cute about this. The only reason we were forthcoming in we have 2 that are ongoing right now is to show that we have allocated some capital outside of the Eagle Ford and outside of the Bakken. But other than that, we're going to ask you to respect that once we have some information that we feel is valuable to you guys, we'll disclose it.

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

Okay. This is my follow-up question. Understanding that you actually have quite a nice balance sheet with lots of elbow room and understanding that historically, you guys much prefer really doing stuff organically and really finding a place early on, do you have the appetite to actually go out there and buy something a little more developed or bigger package or even producing assets? I mean this is just a general philosophical question for you all.

Randy L. Limbacher

I think, in general, what we're looking for is the highest quality drill bit inventory that you can find going forward. So I would probably just restate our basic strategy, which is we need to execute really well on the Eagle Ford. We continue to think about it as being 60 completions or so a year of run rate. We'd like to test a couple of new ventures play per year. So that's sticking with the organic side. But that's probably no more than 5% to 10% of our overall capital in a given year. And then as we look out to the future though, we do see there's a lot of cash flow the company is likely to generate. We think we're fairly close to being cash flow positive. And so for that larger chunk, if you will, we are thinking in terms more of looking at de-risked acquisitions as opposed to the organic side of it. So there's a balance in there. So I think maybe the short answer would have been, "Yes, we're interested in things that are de-risked, probably not interested in just going out and buying PDP-type reserves though.

Operator

And our next question comes from the line of Brian Corales from Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

A couple of questions on the Eagle Ford. One, with the 3 rigs running in Gates Ranch, I mean, is it safe to assume that the rig count that you put in the presentation that's going to stay roughly the same in 2013? Or are they going to go maybe to the some of the more oily areas?

James E. Craddock

Brian, I think the way to think about it is and I think we elsewhere say 2 to 3 rigs going forward. For kind of a 60-well completion pace, I think it's reasonable to assume about half of those will be in Gates Ranch and the other half will be in the other areas we've been talking about, Briscoe, Central Dimmitt. It doesn't take 3 rigs all year long to stay ahead of a 30-well pace. It will probably bounce around a little bit.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay, that was helpful. And then in terms of the cost, the $7.5 million to $8 million, can you maybe talk about over the last 2 quarters or 3 quarters where you're seeing costs decline? And then if you look out to 2013, '14, where you can see potential other savings? And I know some of the deeper areas, they cost more like the Karnes Trough, but is it -- I don't know is it more on the completion side, the drilling side, the things that additional savings you may be able to find?

James E. Craddock

Most of the savings we've seen, in the course of this year, have been more on the completion side. And so I would say, we still believe that even though rig rates have been a bit sticky, there's pressure building there. We've seen a number of rigs being deployed in the play decline a bit. I think all the company's out there are getting more efficient. And so that's probably another area we'll see some added competition, maybe some improvement in cost. Things we're working on is like a lot of operators, looking at what the right mix is in terms of the number of wells per pad and then we're also going to be doing a pilot test early next year on, longer laterals. You may actually see higher per-well cost, but reduce the number of wells required. And so those are the kinds of the things we'll be testing out there. And then I guess the last thing to mention is there's a lot of press around core costs earlier this year. I think everyone knows those costs have declined and some of that is yet to fully ripple through the cost structure. So I think there might be a little bit of added benefit there.

Brian M. Corales - Howard Weil Incorporated, Research Division

And if you don't mind if I just squeeze one more in? You talked about 60 completions next year. But with the good balance sheet and the good returns that you see, I mean, why not make that $75 million, $90 million, increase the activity of the completions, use the balance sheet a little bit? And just your thoughts there and I'll hang up and listen.

Randy L. Limbacher

I appreciate the comment. I think I'd stay pretty consistent with the way we've answered that in the past. We think 60 completions a year is a very prudent run rate for us to be on. I think that when you look at the absolute growth that it delivers as a company, we're probably in a minimum in the top quartile, probably in the top decile of the peer group of delivery on top line growth. So as far accelerating much beyond that, I don't think we get much incremental value in the stock for doing that. I think the other thing that we don't want to get too far ahead over our skis on the -- as compared to the marketing side of it. So we've had a very deliberate plan and I think one that's been differentially successful on that. We're going to take a look at the marketing side of it for 2014 and beyond. And so I think we're pretty comfortable with where we are and given kind of the state of the worldwide economy, I think we're on a very prudent pace and run rate right now.

Operator

And our next question comes from the line of Leo Mariani from RBC.

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

Could you talk a little bit more sort of grassroots leasing opportunities in the Eagle Ford? I think you've mentioned that part of that was in your budget. Are you seeing much out there on that side? And just kind of any color on that, that'd be helpful.

John D. Clayton

Leo, this is John. If you look at -- if we can design the perfect lease, it would be a nice rectangle. And if you look at a lot of these leases and go throughout all of our assets, we're pretty fortunate to have some blocky leases. However, the geometry on some of them is not very conducive to lateral wellbores, especially when you run a full development mode on pad drilling. So within the Eagle Ford, the efforts have been on squaring up the geometry so we can be more efficient with placing our wellbores. As Jim mentioned, leases are pretty expensive and so as from a full acreage amount, it doesn't add to a whole lot but from an incremental, putting a well in there, it adds quite a bit of value for us.

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

That's helpful color for sure. You mentioned participating in Webb County kind of going forward. Can you quantify what the interest is there? And who is the operator there?

John D. Clayton

Anadarko is the operator, and we've got a little over 7%.

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

All right, that's helpful. And I guess last one for me, noticing that your NGL production ticked down slightly here in the third quarter versus 2Q. I wasn't sure if there was any issues with ethane rejection or anything like that potentially affecting the number here. Is it just more of a mix of wells you that brought on the quarter?

John D. Clayton

Leo, that's exactly right. It is mix-related. As we've said before, we're going to 4 different plants. And depending on situations in the quarter or in the month, that mix can change. On ethane rejection, we did not see any ethane rejection, and we don't anticipate seeing that. In fact, the number of our plant contracts are fixed recovery contracts. So there'll be a fixed amount of ethane associated with those.

Operator

And our next question comes from the line of Neal Dingmann from SunTrust.

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

Just a couple of thing. I know I've [indiscernible] have even asked in the last call. I'm just wondering is that -- a lot of these Pearsall results have been developed. Just wondering now, for you or Jim or John, just your thoughts on your acreage, if any of that has changed? And as you look for some of this new acreage, is that -- some things you're targeting as well?

John D. Clayton

Yes, Neal, this is John. I think the effort by our industry as it pursues the Pearsall is to -- identifying reservoirs is, obviously, one aspect but maturity is the other. So where is the dryer gas going to be, where is the condensate going to be and where is heavier liquids going to be. And that's the thing the industry is trying to unlock right now. And we're watching it. We've got a pretty spread-out acreage position when you start looking at the number of counties we're in. And so I think it would be fair to say that some will probably be dry gas and hopefully some will be a little heavier on the liquids side.

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

Got it, got it. And then just one last one if I could. You mentioned in the press release, still about all the locations, I think, almost 350 locations still left in Gates Ranch. Just wondering when you look at some of your other areas, specifically the Karnes Trough and then if you'd even throw Briscoe Ranch and some of these others. I'm particularly interested in the Karnes Trough, how many run, how many locations you think you have left there? Could that increase on more down spacing? And then sort of your thoughts about some of the locations on the others?

John D. Clayton

The way I'm looking at our Karnes Trough area is, I think, we only have about, if memory serves me right, 1,900 and some change net acres. We'll have all of our locations drilled by the end of this year, and we should have all of our locations completed in that area of the first half of next year. So just to kind of guide you, I wouldn't start putting a bunch of down spacing in there. It's not that it's not possible. But it's not something that we're planning on. If you move to Briscoe, Jim mentioned we just drilled our first 3-well pad. You start looking at well spacing there. If you use about 50 acres on the well spacing, we've got about 3500 net acres under lease. It's a nice pretty rectangle. It's very efficient on the well count. And I think if you look at our activity there, it's on the neighborhood of about 70 well locations.

Operator

[Operator Instructions] Our next question comes from the line of Gordon Douthat from Wells Fargo.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

So another question on Karnes Trough. As you finish drilling there, where do you see that rig going across your acreage? And does that 60-well target next year given the efficiencies that you're realizing, does that contemplate a 5-rig program or can you get there on 4?

John D. Clayton

Gordon, I think when you lease Karnes Trough, it's destined for one of the other development areas. So again, Briscoe and Central Dimmit are the most likely candidates. And I'm sorry, what was the second part of your question?

Randy L. Limbacher

How many wells per year on a rig?

John D. Clayton

Oh, wells per year per rig. We're making around 16 wells per rig and so obviously, we're now going to need 5. But it is dependent kind of a reminder on as we start new developments in new areas. We've got to ahead of the completion spread. That requires drilling more wells than we complete. So for instance, as we begin to develop out places like Briscoe, we'll have to get ahead of that. That requires a few more wells.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Okay. And then last one for me. In your prepared remarks, you mentioned some facility expansion activities going on in 2013 to get ahead of 2014 production. To what extent -- I know you haven't released guidance on 2013 CapEx, but to what extent should we think about that component as we look at -- as we model CapEx for next year?

John D. Clayton

A couple of broad comments on that. We typically build central tank batteries that support 15 to 20 wells, those cost $4 million to $5 million each. So it gives you a rough idea on the 60-well program that we should be building, let's say, 4 of those each year. And then as we've said before, we're going to make sure that we're ahead of the game on that. In Gates, we've gotten there. We'll probably have 40% of the capacity available to us as we end the year. In other words, each of the facilities will be on average about 60% utilized. But as we move into these other areas, we're going to require some build out there too. So that's the way to think about facilities for next year.

Operator

And our next question comes from the line of Dan McSpirit from BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

You spoke to 60-well completions in 2013, 50% in Gates Ranch and 50% elsewhere. Can you remind me of the split first half '12 and second half '12?

John E. Hagale

In terms of completion count, I think it was fairly uniform. We're 43 wells for 3 quarters, so we're on pace to average about 15 wells a quarter roughly. It was probably a little light in the first quarter and then we kind of have picked up the pace since then and we're on track.

Dan McSpirit - BMO Capital Markets U.S.

Okay. And how many of those at least in the second half or at least do you anticipate will be outside of Gates Ranch?

John E. Hagale

In the second half of this year?

Dan McSpirit - BMO Capital Markets U.S.

Right.

John E. Hagale

Yes, I don't have that count in front of me but I think it's -- right now, our Gates program is fairly uniform each quarter. It was 12 this quarter, so I think it's pretty consistent with that overall split.

Randy L. Limbacher

We can get the exact number and get back with you on that though.

Dan McSpirit - BMO Capital Markets U.S.

Great, I appreciate it. And then second, how do the non-Gates Ranch wells compete with what you've completed at Gates Ranch on field-level economics and payback periods, recognizing the product mix is different?

John D. Clayton

This is John. We like everything we're drilling right now outside of Gates just because it's focused on the liquids window. But what I would draw your attention to is although we haven't done it in Central Dimmit yet, but we have published type curves for Briscoe Ranch, and I think the well cost at Briscoe is probably on the lower end of Gates so maybe about $7.5 million per well. Karnes, although we published types curves, we'll all have that drilled up by this year and completed by the first half of next year. And then as you go across our 8,100 net acres that's all operated in Central Dimmit County. We've given 7-day stabilized rates on the first well in each of those lease positions. As we get more data in that area, we'll publish type curves for that area as well. But right now, if you get wells that have pretty high productivity in the liquids window, you get some pretty high returns on them.

Dan McSpirit - BMO Capital Markets U.S.

Got it. And then last one for me just on DD&A expense guidance for 2013, any help on that would be appreciated? On a per unit basis, as you look at 2013, and you weight the drilling to maybe more oily completions, how would the DD&A expense change over time?

John E. Hagale

I don't -- this is Hagale. I don't have that yet. We've given you fourth quarter, but I don't see DD&A moving dramatically next year. We haven't lined out the budget yet but I think overall, we're starting to have a pretty big base there. So...

Randy L. Limbacher

I mean the program pace looks to be pretty consistent. The reserves per well seems to be pretty consistent and the cost structure seems to be pretty consistent. I know that's not giving you an exact number or range, but...

John E. Hagale

I mean you are correct. As you do some oily wells, it could move a little bit. But I don't think it'd be enough to change your model that much.

Operator

And the next question comes from the line of Michael Hall from Baird.

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

Apologies if it's already been asked, but I was just curious on kind of the mix and how do we think about the direction as we move through '13. You had the Karnes Trough fault coming on, a lot of high rate oil there at 64% liquids here in October. Is that a sustainable rate? Or to your point when you drill through that inventory, does that start to kind of trend down towards the end of '13 in terms of total liquids mix?

John D. Clayton

Good question, Michael. And we did touch on it just a bit but your question gives me a chance to mention one thing about the October number. We mentioned October at 64% liquids -- that there was a component in that number that was related to higher plant recoveries from a prior period higher than we anticipated. So it affected the number a bit. And for that reason, we're guiding folks on the 4Q numbers to think more in terms of the 62% liquids percentage going forward. As far as 2013, again, we don't have all the details to provide there yet, but the program ought to be relatively consistent. Randy said earlier, Gates Ranch wells are about 55% liquids and then you start mixing in the oilier properties outside of Gates, you get up to that range. And just a reminder, we experienced some pretty lumpy results this year that were related to Klotzman wells coming out. So we've already seen some of that and that's embedded in some of the numbers we're reporting in 3Q.

Operator

And our final question comes from the line of Joe Magner from Macquarie Capital.

Joseph Patrick Magner - Macquarie Research

Just a question, I think there's a comment made in the prepared remarks about the '13 growth profile maybe being more back-end loaded. Can you just kind of -- did I catch that right or was that a reference to 2012? I'm not sure.

John D. Clayton

Joe, that was referring to 2012. So we've been saying that for some time. We're just reiterating that, that has been the case and will continue to be the case this year, but it wasn't referencing 2013.

Randy L. Limbacher

Yes, it's kind of a thank you for your patience on that and trusting us. I think we did what we said we would do but it was a reflection of '12.

Joseph Patrick Magner - Macquarie Research

Okay. I just want to make sure I had that right. And then just curious, a sort of an ongoing topic of discussion, well performance under different spacing tests, just curious if you have an update on the performance? And whether you have any, I guess, update on thoughts of whether it's producing from virgin reservoir, if there's any sort of acceleration of recovery taking place between wellbores? And just curious if there's any variance by area on that analysis?

John D. Clayton

Joe, this is John. We have yet to see any acceleration indicators. There is a slide out there that's on our presentation deck that we showed. We've got 9 wells now located in the center part of Gates and the significance of having 9 wells and some test data is important because 7 of those interior wells are all 475 feet apart. But it will be a good test for us. But with the reservoir simulation we're doing and the actual well results we're seeing, we've not seen any interference on 475-feet wells nor have we seen any on the pilots that we have that are spaced as tight as 425 feet apart. So it's one of those things that the more you learn about it on a good reservoir, the more comfortable you feel about it. And so right now, Gates is under full development at 475 and we've yet to see any -- if you move a little north in the Briscoe, although we've just now started pad drilling up there and we'll get a better handle on it, the data that we've gotten, the work that we've done, says that those wells will be spaced on about 50 acres.

Joseph Patrick Magner - Macquarie Research

Okay. And then I guess what's the -- is that 50-acre spacing the current plan for Central Dimmit?

John D. Clayton

We'll watch these 3 wells that we have. But yes, I think it's more on strike with the Briscoe-type rock, especially if you look at some of the results we're seeing on the Western block on Lasseter & Eppright.

Randy L. Limbacher

I believe the moderator said that was the final question we had. So I appreciate your attendance on the call today. I think just reiterating a couple of the keys, I think the company is set up very nicely headed into 2013. We're operating well. We've seen the success in the Central Dimmit program and as well as continued success with the Eagle Ford infill program at Gates Ranch. So I think we've got a lot of flexibility on how we allocate capital around that for next year. I think if you look at our exit rates, they've been very -- we think they're going to be very strong this year. So that's setting us up well for 2013. As far as facilities, capital and having wellbores drilled to kind of get ahead of the game for next year, I think Jim and the operating folks have done a good job setting us up on that front. On the marketing end, 2013 seems to be pretty well positioned for us to move our product. Chad, our head of marketing is looking at what we do for 2014 and beyond. But I think we're positioned well there. The balance sheet is in good shape. We still have good liquidity. We put some hedges in place to protect against the downside for a pretty significant portion of next year's production. And I think as you look forward, assuming prices continue to cooperate, the Eagle Ford program is pretty close to being cash flow positive. So we like where the company stands right now. I think there's going to be a few of us around today as well, probably to take some questions by phone later on if you need to. But I will thank you for your attendance on the call, and I'll turn it over to the moderator for the closing replay information. So again, thank you very much, and have a good day.

Operator

Thank you, sir. Once again, ladies and gentlemen, if you were not able to participate in the full call today, an audio replay will be available from November 8, 2012, 2:00 p.m. Central to November 15, 2012, 11:59 p.m. Central by dialing (855) 859-2056, or for international participants, (404) 537-3406, and entering the conference code 40307116. 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 our website and select Events. This does conclude the conference for today. And you may now disconnect. Thank you.

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