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Rosetta Resources (NASDAQ:ROSE)

Q1 2013 Earnings Call

May 07, 2013 11:00 am ET

Executives

Don O. McCormack - Chief Accounting Officer, Vice President and Treasurer

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

Brian M. Corales - Howard Weil Incorporated, Research Division

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

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

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

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

Operator

Good morning. Welcome to Rosetta Resources' First Quarter 2013 Conference Call. Joining us this morning from Rosetta are the following individuals, Jim E. Craddock, Chairman, President and Chief Executive Officer; John E. Hagale, Executive Vice President and Chief Financial Officer; John D. Clayton, Executive Vice President and Chief Operating Officer; Don O. McCormack, Vice President, Treasurer and Chief Accounting Officer. Today's conference is being recorded [Operator Instructions]. If you're not able to participate in today's conference call, an audio replay will be available from May 7, 2013, 2:00 p.m. Central through May 14, 2013, 11:59 p.m Central by dialing (855) 859-2056, for international, (404) 537-3406, and entering conference code 50344019. A replay of the conference call may also be found on the company's website, www.rosettaresources.com. To access the replay, click on Investor Relations section of the 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 first quarter 2013 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 remind you that certain statements included in this morning's call and presentation may be forward-looking and reflect the company's current expectations or forecast of future events based on the information that is now available. Please refer to the forward-looking statements in our earnings release for more information.

With that disclaimer, let me review today's agenda. Jim Craddock will review our overall first quarter 2013 performance and provide an update on the status of our pending Permian Basin acquisition. Next, John Hagale will provide a brief financial review over the period, followed by John Clayton, who will discuss our operating results. Jim will then open the lines for Q&A. Also, we would ask that participants limit themselves to 1 primary question and then 1 follow-up.

Let me now turn the call over to Jim.

James E. Craddock

Thanks, Don. Good morning, everyone. We appreciate you joining us this morning. Let me begin by saying that 2013 is off to a great start for Rosetta. We achieved a first quarter trifecta of record production, record cash flow and strong earnings. We also announced a key strategic acquisition during the quarter, a direct result of the successful execution of our unconventional resource strategy to pursue new growth opportunities and build our inventory of oil-rich repeatable projects.

Let's review our list of major accomplishments for the quarter. We set all-time records in daily production for oil, NGLs and total equivalent production. Discretionary cash flow set an all-time record. We recorded sequential Eagle Ford daily equivalent production and oil production growth for the 13th consecutive quarter. Total LOE on a unit basis declined 4% from the prior year and 17% from the fourth quarter. Our credit facility was amended, increasing the borrowing base to $800 million. We announced a significant acquisition, adding a new core operating area and entry into the Permian Basin, and in the month following the end of the quarter, we successfully completed debt and equity offerings, raising more than $1 billion of capital.

Going into a bit more detail, total daily production for the quarter was up 39% from the same period 1 year ago. We recorded 54% year-over-year and 6% sequential growth in our Eagle Ford volumes.

We will provide additional comments on this quarterly highlights later in the call, but we're certainly pleased with the strong starting and are confident in our ability to deliver on our expectations for the year. Rosetta is well-positioned to achieve our growth targets this year and beyond. An important contributor to that long-term growth is our soon-to-be acquired Permian Basin assets. The $768 million acquisition was announced on March 15 and is subject to customary closing adjustments with an effective day of January 1, 2013. We are working through the last due diligence items on the acquisition, which is scheduled to close next week. John Hagale will provide some color on the transaction financing in his comments.

From an operational perspective, the acquisition diversifies our asset base, provides a new core area for our company, adding 53,000 net acres and approximately 800 net vertical drilling locations. It is part of our ongoing strategy to pursue new growth opportunities and build our inventory of repeatable liquid-rich projects. We continued to seek out and evaluate asset acquisitions in and around our 2 core areas. While it's not likely that we will pursue another acquisition comparable in size to the Permian Basin transaction for now, we remain in the hunt and are prepared to pull the trigger when the right bolt-on opportunity presents itself.

As you read in our earnings press release, we did reaffirm the 2013 guidance ranges provided in mid-April for capital, production and expenses, pro forma for our pending acquisition. We expect to spend $840 million to $900 million of capital to run a 5- to 6-rig program in the Eagle Ford, and the Delaware Basin program with 3 rigs increasing to 6 during the year. Our capital program will be funded from internal cash flow and proceeds from the previously mentioned offerings, supplemented by borrowings on our current credit facility. John Clayton will discuss our 2013 capital guidance later in more detail.

During the quarter, we operated development activities throughout our Eagle Ford assets. In total, approximately 86% of our current Eagle Ford inventory of locations remains to be completed. We ended the quarter with 38 drilled wells awaiting completion, 21 of which are located on Gates Ranch. In the oily Karnes Trough area, 7 of the drilled wells are awaiting completion on the Dubose lease, and we expect to have all 8 remaining locations on production by midyear.

Briscoe Ranch also has 7 drilled wells awaiting completion and we will be busy in that area through 2016. We are reaffirming our full year average daily pro forma production guidance range at 51,000 to 55,000 barrels of oil a day equivalent with an anticipated extra rate of 56,000 to 60,000 barrels a day equivalent.

Overall, our performance in the first quarter of 2013 provides a solid base and puts us on track to deliver our full year production growth and cost targets.

Looking ahead to the second quarter, we expect to provide more detail on our post-close development plans for the Permian assets, as well as more clarity on the progress of various key well tests.

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

John E. Hagale

Thanks, Jim. As a reminder to our audience, 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 and are available on our website.

Net income for the first quarter increased to $53.5 million or $1.01 per diluted share versus net income of $22.3 million or $0.42 per diluted share in 2012. Adjusted net income, that's non-GAAP, increased for the quarter to $62.5 million or $1.18 per diluted share. Those exclude unrealized losses on derivatives. The increase in net income for the period is primarily due to production growth and higher liquids mix. Please note that the income tax expense for the quarter included a nonrecurring item that resulted in a lower average tax rate. We don't expect that trend to continue.

Turning now to revenues for the first quarter. Revenues, excluding derivatives, were $190 million compared to $130 million for the same period in 2012. First quarter revenues, including realized derivatives, were $192 million in 2013 compared to $132 million in the prior year. Year-over-year growth in revenue was due to increased oil and NGL production and higher average oil prices.

For the period, including the effects of realized derivatives, 56% of the revenue was generated from oil as compared to 47% in 2012, and 26% from NGL sales as compared to 31% 1 year ago.

First quarter revenue from oil sales including realized derivatives increased to $108 million or 72% from the $63 million 1 year ago. Oil revenue was also favorably impacted by price increases that was $3.74 a barrel higher than the prior year, and that includes realized derivatives.

We continue to guide full year oil pricing to roughly West Texas Intermediate. I'd like to remind you that Rosetta's oil revenues include sales from both crude and condensate. As I mentioned on our fourth quarter call, Rosetta is not experiencing the level of discounts on condensate that are being quoted by some other industry sources.

Our first quarter average realized oil price, when you exclude all derivatives, was $98.45 a barrel compared to WTI for the quarter of $94.36. I would caution you though, and say we continue to guide to roughly WTI for our realized prices. I think if you use that, you'll be safe in your models as these numbers continue to fluctuate.

The most notable change on a cost perspective for the quarter was a 17% drop in total lease operating expense on a unit basis compared with the fourth quarter, and a 4% drop versus the prior year. That number includes direct LOE, workovers, insurance and ad valorem tax. We also experienced an 8% decrease in Treating & Transportation cost on a per unit basis versus the first quarter of 2012, and we are essentially flat compared to the fourth quarter.

The decreased transportation costs were due to greater volumes coming from our Karnes Trough area where unit Treating & Transportation costs are lower.

Our pro forma expenses for 2013 was included in the press release and is outlined again in Slide 5. These estimates are unchanged from the pro forma guidance we released in April.

We continue to actively work our hedging program and add derivative positions to our production. During April, we executed additional derivative transactions for natural gas production, including colors for 2013 and swaps for 2013, 2014 and 2015. A detailed summary of our derivative position as of April 30 is attached to the press release.

On the financing side of things. On April 12, based on just the increase in our value of our Eagle Ford assets, we amended our credit facility and increased the borrowing base from $625 million to $800 million. On April 15, we launched a $1 billion capital markets transaction that included approximately $300 million of equity and $700 million of bonds. Both offerings were oversubscribed even in a challenging equity market the week we launched.

In late April, we completed the public offering of 8,050,000 shares of our stock and secured net proceeds of $329 million. On May 2, we completed the issuance of 700 million in aggregate principal 5.625% senior notes due in 2021. We utilized most of the proceeds from the equity offering to repay our outstanding indebtedness under the credit facilities, and on May 2, we had no borrowings outstanding under the facility and $800 million available to borrow under the facility.

That's all I have for now. Let me turn the call over to John Clayton.

John D. Clayton

Thanks, John, and good morning, everyone. This morning, I would like to update you on our first quarter operational performance, a quick review of our capital project inventory and our planned activities for the remainder of this year.

First quarter 2013 was another record quarter for Rosetta as we achieved all-time highs in total production, oil production and NGL production. We also achieved total production growth and oil production growth in the Eagle Ford for the 13th consecutive quarter. Capital expenditures for the quarter were $161 million, and we drilled 24 gross wells and completed 17.

Our average daily production for the quarter was 47,000 BOEs per day, up 39% from the prior year. Keep in mind that we also sold roughly 2,500 BOEs per day of non-core properties during 2012. This first quarter production number includes 12,400 barrels of oil per day and 16,500 barrels of NGLs per day, both record levels for our company.

Total Eagle Ford production was 46.8000 [ph] BOEs per day, up 54% from the prior year and up 6% sequentially. Eagle Ford oil production grew by 67% versus first quarter 2012, and increased by 6% when compared to the fourth quarter oil production.

Overall, liquids production for the quarter represented about 62% of total production. Oil production was 26% of total production, up from 22% in 2012 and flat to the fourth quarter.

Slide 7 in our presentation shows our historical Eagle Ford production profile by quarter. You can see how the total production and oil production has grown for more than 3 years. This significant production growth we have achieved in the Eagle Ford also requires producing facilities to handle the increased volumes with an associated operating expense.

In the first quarter 2013, direct LOE expenses totaled $8.4 million, a 43% increase over 2012 on an absolute basis. These incremental costs were mostly associated with handling facilities to handle the increased oil production in the Karnes Trough area, as well as the increased number of producing facilities associated with our Briscoe and Central Dimmit areas as we successfully stepped out and delineated these assets.

On a unit basis, first quarter direct LOE increased slightly in the first quarter from $1.89 per BOE in 2012 to $1.97 per BOE in 2013, an increase of roughly 4%.

Sequentially, however, first quarter LOE was 20% lower versus the fourth quarter result of $2.46 per BOE. Overall unit operating cost across our Gates Ranch and non-Gates Eagle Ford assets contributed to these improvements.

Now, let's review some of the highlights of the quarter. We've operated 5 to 6 drilling rigs, 3 at Gates Ranch, 1 in the Karnes Trough area, 1 at Briscoe Ranch and 1 in the Central Dimmit County area. We've completed 17 wells, and at the end of the quarter, we had 38 wells that have been drilled and awaiting completion. We continue to also see the improvements in execution of our drilling and completion cycle times, which are benefiting from pad operations and longer laterals. For example, at Gates Ranch, where 4 well pads have now become the standard and replaced 3 well pads, we are testing 5 well pads and have a sixth well pad scheduled. Although the lower cost estimates that we guided last quarter were based on 3 well pads, we're interested in seeing if we can further increase our efficiencies with these increased well pads.

At Briscoe Ranch, we are about to drill as many as 8 wells from a single well pad, and that activity will begin in a few days and last into September. So needless to say, our technical staffs are pushing the limits to further improve our cost structure and increased efficiencies.

In our Central Dimmit County area, in an effort to optimize the geometry of the leases, we have now drilled 2 7,000-foot laterals and will begin testing completion designs that include 25 to 30 stages per well.

Now, let's visit briefly on well spacing at Gates Ranch. As you know, we are developing the field with 475 feet between laterals, which equates to 55 acres. We've also mentioned in the past that we have drilled even tighter spaced pilot wells in an effort to better understand drainage patterns. With that said, we've now begun to drill and test a few additional areas on tighter spacing in an effort to determine what the true ultimate recovery of the field may be. We have not adjusted our development spacing pattern any tighter than 55 acres, but we continue to test a few concepts to the drill bit to increase this field's ultimate recovery.

Now, let's talk condensate, specifically condensate yield. Recently, we have had some questions about fluctuation in our condensate percentage as a percentage of our total production. There are several factors on what impacts this percentage, from something as simple as where our completion activities have been located during a certain time period to how many wells in a particular area that we may be proactively shutting in prior to frac-ing the offset pad, to one that may not be as widely understood, which is condensate stabilization. So let me provide some color on what we have been doing in the field that also impacts our condensate yield. During our development program, as part of normal operations, we have been installing, operating and optimizing condensate stabilizers at our central battery locations. This process serves one purpose, to lower the volatility of the condensate in order to meet pipeline specs prior to us sending our oil and condensate down a third-party gathering pipeline. When we do this, we are essentially cooking the condensate and intentionally driving off the lighter ends and turning them into vapors, which ultimately end up as NGLs. The end result is a more stable condensate barrel that can now then be sold directly into pipeline-connected markets. This barrel does, however, experience some shrink. Additionally, our third-party oil gatherer has also begun to do the same process at their centralized facilities to ensure that the co-mingled barrels meet the specs of the downstream pipeline markets. It is our goal at Rosetta to stabilize all of our condensate in the field to meet pipeline specs so that we do not experience any additional shrink from the gatherer. We think this is the most efficient way to stabilize our barrels and also gives us control of the process. My point here is that although we are not yet fully optimized in doing this, we have made tremendous progress over the past several months, and we should begin to see a reduction in historical shrink that has been associated with the stabilization process.

Now, let's talk briefly about activity in our Karnes Trough area. In the Karnes Trough oil area, drilling and completion operations are approaching full development. On the oil-rich Dubose asset in Gonzales County, 1 location remains to be drilled and 7 drilled wells are awaiting completion. By midyear, all 10 Dubose wells should be on production.

Before we move to inventory, I would like to make a quick comment on our exploratory Pearsall activity mentioned on the fourth quarter call. We now completed the facility construction and made progress on the pipeline connection required to handle the H2S and safely test the Pearsall well on our Tom Hanks lease. Although we had hoped to have something to report on this call, we're now expecting to be in a position to share the test results on this well next quarter. In short, it has taken us longer than we had expected to get this well tied in to properly test the well safely.

Moving on to inventory. I would now like to turn your attention to Slide 8, which shows our updated Eagle Ford inventory table. As you can see, we have built an exceptionally high-quality project inventory in the Eagle Ford, most of which has been successfully delineated. At our current Eagle Ford pace of 60 to 65 wells per year, this inventory represents 13 to 15 years. Pending the close of our Permian Basin acquisition sometime next week, we will add another 1,300 gross or 800 net locations to the company's inventory on what we consider a fairly conservative 40-acre vertical well spacing program.

Finally, let's turn to a few comments on the pro forma outlook for 2013. As Jim mentioned, we did reaffirm the 2013 guidance ranges for capital, production and expenses, pro forma for our pending acquisition. Excluding acquisition capital, our 2013 pro forma capital guidance is expected to range from $840 million to $900 million. This capital program is based on operating 5 to 6 rigs in the Eagle Ford and initially operating 3 rigs and ramping up to 6 rigs in the Permian.

Approximately $600 million will be spent for development activities in the Eagle Ford, which includes about $55 million for facilities projects. Approximately $175 million will be allocated to operated and non-operated development activity in the Permian, including about $7 million for facilities projects. The remainder of the capital is for new ventures and other corporate.

We're also reaffirming our pro forma full year daily production guidance range at 51,000 to 55,000 BOEs per day, as well as the estimated year-end exit guidance of 56,000 to 60,000 BOEs per day. We've also reiterated our pro forma expense guidance. The numbers were adjusted to reflect the impact of the pending Permian Basin acquisition, as well as some other minor ups and downs.

Of note is the impact of the acquisition on increasing our direct LOE, primarily due to the higher operating cost related to the Permian Basin assets. Pro forma direct LOE is expected to average $2.55 to $2.80 per BOE for the full year 2013.

Before I turn the call back to Jim for final comments, I would like to thank our technical teams who continue to do a remarkable job.

With that, I will turn the call back to Jim.

James E. Craddock

Thanks, John. I hope our comments this morning have provided some perspective on our results to the first 3 months of 2013 and what you can expect from Rosetta for the remainder of this year. We're looking forward to the pending expansion into a new core area and expect to deliver another year of outstanding performance.

Before I turn the call over to Q&A, I'd like to take the opportunity to thank our employees here at Rosetta. Whether it was excellent capital execution, support of those efforts, pulling down a key acquisition or moving to a new office, our team here has done a great job.

Let's now turn the call back to the moderator so we can take your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Brian Corales from Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

A question more on the drilled but not completed backlog in the Eagle Ford. I mean you're at 38 at quarter end and still plan to drill more wells than complete. Can you maybe comment on when do you start -- when do you plan on accelerating that?

John D. Clayton

Yes, Brian, this is John. It's a good question that we've started to get as we moved outside of Gates Ranch. And the reason we got such a backlog is the way we do what we call a Buffer Paddy concept, and we try to get separation between producing wells and then our frac spread that goes on our locations. And as we fine-tune that, it's not just how many well locations you are away from where you're initiating the frac, but in some areas, the orientation of it. So as we moved into Briscoe, we had to get ahead before we started completing wells, and the uncompleted to producing well ratio there is pretty large right now, and you compare that to Gates, which is pretty low because we're in development. I don't see 2014 as having as many drilled but yet completed just because we're in development mode now at Briscoe and also Central Dimmit. But if we were to pick up additional acreage in the play, then we would go out and get ahead by drilling half a dozen or a dozen wells ahead of the completion schedule. But sometime maybe next year, we ought to look for that number to be equal on drilled and completed wells, unless we step into another area.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. That's very helpful. And then on the cost, now you've talked about more wells per pad. Can you maybe talk about what that potentially could provide in cost savings?

John D. Clayton

Yes, this is John again. We're not guiding to any lower cost now. We're pretty excited about the ability and the efficiencies that we think are out there as a possibility. But when we went from single well pads to 3 well pads and started getting that procedure lined out, we reduced our well cost in the range of 10% to 15%. And we were able to do that by cutting down standby time for expensive frac fleets, and when we're pumping down 1 well, we'll be setting plugs or perforating on another. I don't think you're going to see the same 1:1 ratio on that gained efficiency. So I don't think it's going to be that dramatic as we move forward. But historically, the way we've acted is once we've seen the cost flow through our accounting systems and AFEs closed and behind us, we try to get at least 6 months data before we come out and change our cost guidance. So we're just now embarking on this, and if we were to see some cost savings that were significant enough for us to change our guidance, we probably wouldn't be announcing that until the later part of this year or early next year.

Operator

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

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

By that 7,000-foot lateral that you talked about, I'm just wondering, kind of going forward, is that designed -- will that potentially become more common? And just wondering, with something like that, any estimates? Yes, I know you said you're not assuming cost coming down yet. Just sort of assuming what kind of well costs are you going to have around that?

John D. Clayton

This is John again. It does cost a little more to drill those wells. I don't think that when we look at the geometry of the leases, I would put that as the primary driver of how we try to be efficient with the capital. It's a lot more efficient for us to drill 1 7,000-foot well if that's the geometry of the lease as opposed to maybe 2 3,500-foot laterals. So I don't see us going at Gates Ranch at 7,000-foot development. I think we think the optimum link there is 5,000 based on the geometry of that lease. But it does cost us. We're increasing our frac stages, maybe even nearly as much as because we're increasing the density as well, too, but twofold on it. So well cost on a 7,000-foot lateral could be a couple of million dollars more once the cost all flow through on the extended number of stages. But the primary driver there was the choice based on the lease was to either develop on 7,000-foot or 2 3,500-foot laterals, and it just made more economic sense for us to go 7,000.

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

Got it. And then just last question. I think, I know you answered this, but as far as lease expirations, either obviously, it didn't seem like, appeared like you have anything like that in your Eagle Ford. Just wondering, some of that new acreage you picked up, it didn't appear, I think, when you talked about on the acquisition call that there was anything around that. So I guess, number one, is there any issues on either play for that? And then number two, are you all seeing some opportunities maybe in the Eagle Ford to pick up little pieces that might have some issues if you're able to bring a rig in and maybe hold some of that?

John D. Clayton

Yes. I'll start with the lease expirations in the Eagle Ford question, and most of our acreage is moving in to continuos drilling obligations, which was one of the reasons why we wanted to go out and get it delineated so we can start pad drilling in development. So I think your assumption's right. Although we've got continuous drilling obligations in the Eagle Ford by far, the majority of it is, I might not call it proven by SEC definitions, but it's delineated enough to where, regardless of the lease terms, we would be out there doing -- or developing it. So if we move to the Permian, 2013, we'd probably have to have about 2 to 3, I think we call it 2.5 rigs running out there, drilling vertical wells to keep that lease position intact. However, as you move into 2014 and '15, I think we'll peak out somewhere in the, again, dependent -- depends on cycle time, but 5- to 6-rig pace to keep all the continuous drilling obligations intact there. So it's not very onerous on keeping it together, you just have to make sure you have a steady program going at it. And your last question...

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

Just far as acreage in Eagle Ford. Correct.

John D. Clayton

Enough acreage in the Eagle Ford, great question. We did get successful towards the end of last year with we're coming out of this 36-month window when people picked their primary term leases and they're finishing up. And if you are a company that's got a backlog of inventory enough to keep 5 to 6 rigs running, sometimes having a rig gives you quite a bit of option value. And so we did pick some up at the end of last year. I think we talked to -- when we had a slide out there on the third or fourth quarter call of some of the acreage we picked up, and we are drilling some of that acreage right now.

Operator

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

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

In Reeves, 2 quick ones. How's the Gaucho state been holding up? And can you remind us when you plan to do your first five-spot 20-acre test?

John D. Clayton

Yes, Welles, this is John. We haven't given any well updates on the Gaucho well. I'll tell you though that not only with the wells that Comstock had drilled, especially in the upper Wolfcamp, but some of the results coming in from other operators in the Wolfcamp out here in close proximity, we like what we're seeing horizontal. I think somebody told me the other day, there are 16 rigs drilling horizontal wells in the Delaware Basin in Reeves County alone. So we're pretty pleased with all the data that's going to come to market. I think you guys will start seeing some of that. Some of it's coming out now. But with that much horizontal activity, we're going to get a lot of information on it, and early results are saying that it's going to be something that's going to be attractive, and it's going to be very competitive with the way we valued the original acquisition, it was vertical 40-acre spacing. So, I mean, I -- we're not going to update you on the well, I guess, is the short answer. But I'll tell you, we're encouraged everyday that goes by on the activity and the way these wells appear to be performing. Although, you know better than most people, these wells decline quite a bit. You've got to watch that before you can start publishing type curves. And that's how we've acted in the past, is once we get enough data to put a type curve out there that we're using, we'll go ahead and do that for you guys.

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

Okay, perfect. And any timeframe for that five-spot 20-acre test that you guys have talked about?

John D. Clayton

Sorry, I forgot about that. We're trying to -- we've got 3 rigs running out there now that Comstock has. I think you'll see us add our fourth rig. We're hopeful to do it by June 1. We're in negotiations right now with several contractors, but we'll have a fourth rig out there at least in the early part of June. So once we start getting ahead and get those rigs underneath this, then we'll start putting them on the five-spot programs. And our goal is to put it on maybe by the end of the year. But right now, we're focused on getting the magnitude of services to keep us going with a 6-rig program. But that is something that's high on our list.

James E. Craddock

Yes, and I would just add. Just a reminder to everyone, we haven't closed this thing yet. We do have a transition period that we'll work through with Comstock before we are fully on the ground taking over that may last as long as mid-August. So our goal is to get our feet under this thing and get operating out there before we can start doing some of the things that will drive inventory projects up.

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

Perfect. And is 60,000 still around the right number for your Pearsall perspective acreage or has that nudged up a little?

John D. Clayton

Yes, I think when we talk about that acreage, we made no bones about it. Most of the stuff that we think we have, Pearsall rights underlies within the dry gas window. So I mean we've seen some strengthening since we probably last talked on gas prices. But we're chasing the liquids window, which is pushing it towards the north. And our percentage in that ballpark is a lot smaller but something we're looking at, something we're focused on. But by far, the large majority of our acreage position with Pearsall rights exist in the dry gas.

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

Okay, perfect. So I guess no leasing update up north then?

John D. Clayton

No, we haven't talked about any of that lately.

Operator

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

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

A question following up on the Reeves County acquisition. I'm kind of curious, have Comstock drilled also 1 well called Balmoray [ph], I believe? Should we expect some results from that? And after that particular horizontal well, are there any in plan for rest of this year? Because from what I heard, it sounds like you guys are going to do mostly verticals. Then, do you have an office in the Permian? I'm just kind of curious.

John D. Clayton

Irene, this is John. I'll start with the last one. We will have a field office out in the Permian Basin. It's important for us to be on the ground out there and, as you know, that's important for us to drive cost out and be on the ground. Our technical staffs, however, are going to stay -- are located in Houston. The Balmoray well that Comstock drilled was the fourth horizontal well. We actually postponed the completion of that well, they had that well scheduled to complete in April. And we're going to wait until we have operatorship of that well. And once we have our guys on the ground, then we'll go ahead and pump that job. The way we design it, which, I would anticipate, probably third quarter-ish, give me some lead way on that but we pulled it off of schedule. It was scheduled for April. Until we actually got it closed, then we can control the operations. The other question, could you repeat it?

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

Yes. After that deal...

John D. Clayton

No, great point. We did value the acquisition on all 40-acre vertical programs. That accomplishes a couple of things. One, you get a big inventory of 30% rate of return projects that are very oily, and that's something that we value quite a lot. But as you know, there's a lot of option value when you've got a worth 1,000-foot of hydrocarbon column. The other thing vertical drilling does for you is it allows you to hold rights to all depths when you drill vertical wells. And it's not to say that we're not excited about the opportunities that are out there that we can drill horizontally. It looks like the upper Wolfcamp has taken off in the area, there's a lot of activity that we're going to go to school on. I don't see us spudding any operated horizontal Wolfcamp wells between now and the end of the year. Our focus is going to be on getting to 6 rigs and getting them drilling vertical wells. I would look for us to drill some horizontal wells next year, and we're going to have a lot more data as an industry in Reeves County by then. And in the last, I would say, is we are participating -- a large portion of our acreage is nonoperating, where we don't control the majority interest of it. And we've recently approved -- one came through the other day that Concho is going to be the operator on and we're going to have a working interest in it, and it's a horizontal well that's targeting the Wolfcamp on our acreage. So although we won't be operating between now and the end of the year, I would look for us to be participating on everything that comes our way from a non-operated position and then get ready to go out on our own next year.

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

Got you. One more follow-up is how long would it take you to drill vertical well to secure all of your acreage?

John D. Clayton

Well, they all go -- they all start going under continuous drilling. So you pick a -- we won't be limited by the number of rigs. So but if you pick the rig pace of, I won't do the math for you, but if you pick a rig pace and then divide by 1,300 gross locations, that'll tell you about the time period. If we get it down to 20 acres, then you could double that. So it's everything out here, real similar to South Texas. We'll go on a continuous drilling obligation where you have to drill so many wells a year.

Operator

Our next question comes from the line of Brian Lively from Tudor, Pickering.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

John, you were talking about condensate stabilization in the Eagle Ford. Just hoping you can elaborate a little bit more on that? Specifically, what's the historic shrinkage that you guys have seen as you've gone to marketing on that? And then as a separate piece, with the installment of these stabilizers, what do you think, on a wellhead basis, you can reduce your downtime by on the condensate?

John D. Clayton

I mean, I'm not sure I can answer all those questions and get you the detail that you probably need, but the whole process, as the play took off, we started this, I think, probably back in April of 2011, and it was more to move the vapors off of the location and as part of our process. What we've run into this year though, or late last year then moving into the first couple of months of this year, is as we're sending some of the stabilized condensate down to the gatherers, it was still over, let's say, a reid vapor pressure of 9. And I think that's the pipeline spec for the area. So they noticed that and then they started doing their own stabilization, and then they charge you for that. And that's something that we probably didn't want to do. So to control it to where we don't overstabilize and get the RVPs down to the 8 range, we start losing condensate, and as you know, it's a lot more valuable than NGL prices. So our goal in the fine-tuning that we've done really over the last 3 or 4 months is to get that RVP of right at exactly 9. That way, we maximize the condensate barrel and then we meet the pipeline specs that the gatherer has to deliver into the main pipes. So that's kind of why we've done it. The shrink difference is -- I don't -- to be honest, I don't know those exact numbers off the top of my head. It's not going to be significant. And it is something that we think that we've seen over time, especially in the last 2 or 3 months, we've started reducing some of the shrink numbers. So when we came in January and February of this year, some of the questions we started getting were, your oil percentage as a percent of total is changing. And we could explain different areas when we bring on Karnes Trough, and we'll be bringing on 10 of dell [ph] Dubose wells or 9 more. But geographic dictates kind of what your oil yields are as a percentage of total production. But the other thing that we're dealing with is we've just now started to optimize where we're shrinking everything ourselves, we're getting the RVPs to 9. When we started doing that, we started getting them below 9, and then we're overshrinking. So that means that we're delivering more NGLs from the field and less condensate barrels to the gatherer. And our goal is to get this thing right at 9 to where we don't overshrink or undershrink. And I don't have the exact numbers on the total shrink and what it changes, but it's just 1 of the 3 things that dictates when we report quarterly volumes, the percentage of oil, where we drill, how many wells we shut in, in areas, and then how we optimize that stabilization.

James E. Craddock

And I would just add again, John mentioned it, we've been doing this for some time. And we're bringing it up primarily to point out an upside, we believe, is out there, which is as we work it, we're seeing a lot of encouragement that we're going to be able to reduce the field shrink that we've been experiencing in the past. But it's been embedded in our numbers for a number of quarters. It's not a new thing. But we felt like it was important to highlight it because as we move forward, we think we're going to see some improved shrinks as we get this thing down.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And my follow-up on that guys is when you think about -- you talked about some of the yield volatility in the wells on the condensate side. Do you think by installing these stabilizers, you will get just better -- you'll be able to smooth out some of that volatility? So overall, your condensate volumes, even on a gross basis, will be higher because of just simply less volatility, less downtime on that just from that yield?

John D. Clayton

Yes. I don't see the downtime as the issue, Brian, as much as when we first started putting in and trying to optimize the stabilization across the entire field, if we overstabilized it, we would see a huge -- not a huge fluctuation, but the RVP could go from something as high as 15 down to well below 9. And any time we're well below 9, we're really converting condensate barrels to NGLs and the product price is a lot lower. So we're able to move production from the well on a pretty consistent basis without downtime now that they're all installed. Now, it's just a matter of fine-tuning it and trying to make sure that we can fluctuate around that 9 RVP. So downtime I don't think is going to be an issue anymore. And we've got most of them all installed throughout our properties now. So that's more of a going forward, not a historical look. But I may or may not be answering your question, but it's more...

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

No, John, you answered it. Yes, you answered it fine. I'll follow up with you offline maybe and just get some more details on that.

Operator

Due to time constraints, our final question comes from the line of Brian Gamble from Simmons.

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

I wanted to start on the cost side, if I may. Great cost control during the quarter, and I'm looking at the annual guidance range. I know it includes the new Permian transaction, that changes things around a little bit. But given where you were during Q1, things imply a pretty dramatic shift even to get to, frankly, below end of guidance for LOE or transport for the full year. I was hoping you could maybe can walk me through the pieces of how you get to that lower end or the midpoint for that matter?

John E. Hagale

I'll start with G&A, even though you didn't mention G&A, and I'd say G&A falls into that same category and we still feel pretty good about the guidance we've given out there. And I'd say there's a few things in the first quarter that made G&A a little lower than what you might normally expect to see. And there are going to be things coming in, in the second quarter in particular, but in the second half of the year, as we continue to ramp up headcount here. But the other thing I'd say is we're going to have transaction costs that will flow through G&A, that won't get capitalized. So on the G&A side -- and we've also got, I think, 9 months left on our old lease as we move. So if you take the old lease, the transaction cost and the fact we're ramping up headcount, we still feel pretty good about the G&A guidance we've given. And I know you weren't asking about G&A. And then the other thing, I'll let John talk to LOE, but on Treating & Transportation, we do believe we have a little bit of a wall here. But we believe the numbers we've got in there are pretty good numbers when you include the Permian. What I would say is, give us a chance to get those under our belt because once we get out 3 to 6 months, we'll have a much better feel on those. But right now, at least on both G&A and Treating & Transportation, I think those are pretty good estimates. Like I say, we'll reevaluate those in a few months. You want to talk about LOE, John? I think it's the same answer, but...

John D. Clayton

Yes, it's probably a little more kind of where we are in the process, the way I would answer. I mean for, let's say, direct LOE, we came in at $1.97 for 1Q, but we're guiding -- I see where you're heading on this. We're guiding $2.55 to $2.80 for the full year. Anytime you take on an acquisition and there's a lot of integration, especially when some component of it is a non-op component, I think we've got 4 non-operated rigs running right now. And when we try to guide, we always try to give you guidance that you could at least count on. So I would -- as you guys do, I would keep track in this quarter-to-quarter. Permian, LOE is higher than what we're seeing in the Eagle Ford. The Eagle Ford wells come on at pretty high rates, so when we talk unit basis, it is. We do also have water disposal issues and hauling that we've got to deal with in the Permian. We've got to get our hands around that. So when we guide towards that after we're operator, I think we'll fine-tune the Permian piece. But we did have a good 1Q, and then we've kind of given you guys some guidance on integrating a new property and a new basin. And startup charges and increased efficiencies always tend to, at least in my experience, beyond the higher end and the lower end, and we try to factor that in when we've given our guidance.

John E. Hagale

And we see some things out there that tell us we don't want to get too optimistic. We want to give you something we think we can work with. But once we get a few months out, we'll take another look at it.

James E. Craddock

And number-wise, just remember that what we've said is we believe direct LOE in the Permian for those wells is $10 to $13 a BOE. Now, that sounds a lot higher than Eagle Ford, but also keep in mind those are 65%, 70% oil wells, so they have a higher net realization as well. But that's what's going into the numbers. Do we hope to lower that? Sure. But we need to get boots on the ground before we can start promising that.

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

Great, appreciate the color. And then just to follow up on something you touched on a little bit earlier, the, I guess, transition service agreement with Comstock, you mentioned a date. I think, Jim, you may have put on a date that said mid-August. But is that the official end of the, I guess, transition agreement? And kind of give me an update on, I guess, just personnel count looking from now until then, and then afterwards, on having enough guys to run the plan for the rest of the year?

James E. Craddock

Yes, I mean, so yes, mid-August is the -- would be the official end. And so we'll look at whether we want to go that long or not, but that's currently what the plans are. And then I'll let Clayton talk a little bit about personnel, maybe.

John D. Clayton

Yes, we -- when we started looking at basins that were oily and which areas to get in, we've got a lot of guys that work here at Rosetta and from other companies that has spent a lot of time in the Permian, working it. And so we've reallocated those guys to the Permian. We're in a hiring mode right now for people with those experiences, but our success is not contingent on it. We've got the people in-house already. I think Irene or somebody mentioned about a field office out there. So we do have a field office out there, and that will be a focus for us, is to get that staffed up and we're on the ground right now interviewing and hiring out there. But lack of staff or lack of experienced staff to get the job done is not going to be a factor for us.

Operator

This does conclude the question-and-answer session of today's program. I'd like to hand the program back to Jim Craddock for any further remarks.

James E. Craddock

Okay, that's all the time we have this morning. We look forward to visiting with you again to discuss second quarter results. I hope you have a good day. Thanks.

Operator

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect.

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