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Rosetta Resources (NASDAQ:ROSE)

Q2 2012 Earnings Call

August 08, 2012 11:00 am ET

Executives

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

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

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

John D. Clayton - Senior Vice President of Asset Development

Analysts

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

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

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

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

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

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

Jeffrey Hayden

Dan McSpirit - BMO Capital Markets U.S.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Operator

Good morning. Welcome to Rosetta Resources Second 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, Chief Financial Officer and Treasurer; John D. Clayton, Senior Vice President of Asset Development; Jim E. Craddock, Senior Vice President of Drilling & Production Operations. 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 August 8, 2012 at 2:00 p.m. Central through August 15, 2012 at 11:59 p.m. Central by dialing (855) 859-2056 or for international (404) 537-3406 and entering conference code 96030005. A replay of the conference call may be found on the company's website, www.rosettaresources.com, for 60 days after the call. To access the replay, click on the Investor Relations section of our website and select Presentations and Events.

At this time, I'd like to turn the call over to John Hagale. Mr. Hagale, you may begin your conference.

John E. Hagale

Good morning, and thank you for joining us for our second 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 remind you that certain statements included in this morning's 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 our agenda for the call. Randy Limbacher will open with remarks about our overall performance for the quarter and the first half. Next, I will provide a brief financial overview for the period, followed by Jim Craddock who will discuss operating results. Finally, John Clayton will update you on asset development activities. Randy will then open the lines for Q&A.

Let me turn the call over to Randy now.

Randy L. Limbacher

Thanks, John, and good morning to everyone. With the close of our second quarter activities and end of the first half of 2012, we at Rosetta have been evaluating the execution of our performance thus far against the expectations we have set in the marketplace for the year. During these reviews of our operational and financial activities, we have become even more convinced that our efforts as an organization are garnering the results that we committed to deliver. We again increased year-over-year daily production by double digits with another quarter of significant growth in higher-valued liquids production. Our Eagle Ford shale program is proving as equally successful in areas outside our Gates Ranch discovery that first established us as the leading competitor in this emerging U.S. energy play. We continue to reduce our per-unit operating expenses as a company as our production base shifts solely to the Eagle Ford shale from our non-core legacy assets that have been sold and the proceeds redeployed into our unconventional resources growth platform. With less than 10% of identified Eagle Ford inventory drilled and on production, we are working hard to realize the value of this extraordinary asset base.

In the Gates Ranch area, we are now confident that the revised 55-acre well spacing will result in the development of over 425 wells with an estimated ultimate recovery, or EUR, of nearly 1.7 million barrels of oil equivalent per well. Half of our 2012 Eagle Ford activity is now situated in 3 areas outside Gates Ranch. As promised, we now have enough production data from our Briscoe Ranch drilling and Klotzman wells in the Karnes Trough area to issue EUR projections for wells in those areas. Keep in mind that production from these properties contains a higher percentage of oil and natural gas liquids, which improves the profitability of these wells and drove our decision earlier in the year to allocate capital away from Gates Ranch to these very profitable plays. John Clayton will break down the numbers for you as he updates asset development activities for the quarter.

Suffice it is to say, we are fortunate to be drilling in what is the sweet spot of the Eagle Ford shale, which allows us to generate excellent returns even at lower commodity prices. Obviously, there's some disappointment about the results of our horizontal drilling program in the Southern Alberta Basin and our subsequent decision this quarter to suspend additional capital activity in the area. John Clayton will provide specific details about our well results and some of the factors that led to our decision. However, we remain confident that given the success of reduced spacing at Gates Ranch and based on the strong type curves we are now publishing for Briscoe Ranch drilling and the Klotzman wells in the Karnes Trough area, we have a derisked inventory that will allow the company to grow at the top of our peer group for many years to come.

Also, as we have signaled in the past, we are now positioned to test other new play concepts that, if successful, expose us to additional growth in future inventory. So our long-term strategy for growth has 3 elements: first, we are going to develop our existing Eagle Ford asset base; second, we're going to invest the significant cash flow that we expect to see from our Eagle Ford program over the next several years into acquisitions in lower-risk plays; and third, we're going to expose roughly 10% of our annual capital to higher-risk new ventures, including new lands and pilot testing. While not being specific, we are currently executing on a couple of these concepts.

Looking ahead to the rest of the year, we still plan to spend roughly $640 million for a capital program that continues to deliver our promised production growth. In fact, as Jim Craddock will discuss with you, we have seen our overall drilling and completion costs come down substantially and we'll use those funds to drill additional wells and add facilities that will give us more flexibility when planning our 2013 program. We're also in good shape to record another impressive reserve replacement ratio for the year, with the preliminary estimate of proved reserve additions to annual production of at least 450%.

Overall, we are pleased with our performance during the first half of 2012. I think we had a strong quarter and would reiterate these key points: our successful down spacing in Gates Ranch and highly economic recoveries we are experiencing from the new areas provide a strong base inventory from which to build the company well into the future. We are also executing on several higher-risk new ventures concepts to expose the company to future inventory adds. We're executing well. We're seeing lower unit costs, both at the drill bit and in field operations. We will drill more wells and add more facilities than originally planned for the same level of capital, providing us added flexibility for 2013. We maintain our production guidance given at the beginning of the year adjusted for the asset sales, and we expect strong 2012 reserve additions. At Rosetta, we are continually grading our performance and our ability to rise to the challenges of our business. Thank you for your ongoing support of what we are trying to accomplish.

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'm 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 second quarter increased to $77 million or $1.46 per diluted share versus net income of $25.4 million or $0.48 per diluted share for the same period of 2011. The growth in net income is primarily due to the increase in production and more favorable product mix, as well as the unrealized gain on derivatives that was $72.5 million or $46.3 million after-tax. Adjusted non-GAAP income was $30.6 million or $0.58 per diluted share, and that excludes unrealized derivative gains.

Revenues for the second quarter were $198 million compared to $111.6 million for the same period of 2011. Revenues where we include only realized derivative gains were $125.5 million compared to $116.4 million for the same period of 2011. Of that amount, 83% was generated from the sale of liquids that includes the effect of realized derivatives as compared to only 60% a year ago. Operating costs continue to improve versus the prior year on a unit basis in the following categories: total lease operating expense, LOE, dropped 9% on a unit basis. That number includes direct LOE, workovers, insurance and ad valorem tax. The improvement was primarily attributable to our success in the Eagle Ford and the impact of the divestiture of our non-core natural gas assets.

Our DD&A rate, depreciation, depletion and amortization, decreased 18% due to significant additions in proved reserves at Gates Ranch during the second quarter of 2011, as well as continued effect of the asset sales. This number will increase as a result of impairing our Southern Alberta asset during the quarter. We expect the DD&A rate will increase by approximately 5% in the third quarter. However, annual DD&A guidance remains unchanged.

Production tax expense dropped 21% on a unit basis. That decrease is due to production tax incentives and the sale of some of the legacy assets. Consistent with our guidance in the past, Treating & Transportation expenses were higher than a year ago. The increase is inherent to our operating model as we grow production from the Eagle Ford shale where our infrastructure is under construction. Specifically, per-unit T&T expense increased quarter-over-quarter due to higher oil transportation costs resulting from the startup of our Gardendale oil terminal in April but is expected to trend slightly lower on a per-unit basis in the second half of the year with increasing contributions from our Karnes Trough area production that realizes lower per-unit T&T cost.

In addition, we have worked hard to stay ahead of the market regarding transportation and processing capacity and now have agreements in place to meet our total planned Eagle Ford production levels for at least 2 years. Moreover, we have access to multiple plants for transportation, gathering and processing that increases our flexibility to avoid operational issues.

We continue to maintain a strong cash position. At the end of the quarter, we held $60.1 million of cash, and our debt-to-capital ratio stood at 30%. During the second quarter, we did receive net proceeds of $17.7 million for the second tranche of the sale of our Lobo and Olmos assets. As of August 1, 2012, we had cash on hand and cash available under our Restated Revolver of approximately $550 million.

Let me close with a few comments about what we expect in the second half. Now that we have revised -- note that we have revised our expense guidance in areas of direct LOE, production taxes and interest expense. Jim Craddock will cover the direct LOE change in his upcoming remarks. I talked briefly about the lower production taxes in my earlier comments, and I would just say in the second half of the year, we expect our interest expense on a unit basis to trend slightly lower than the first half, but we've given you a new guidance there.

We're currently projecting a little higher year-end debt-to-capital ratio of approximately 33%, still very low by industry standards but a few percentage points higher than what we previously projected.

That's all I have for now, and I'll turn the call over to Jim Craddock.

James E. Craddock

Thanks, John, and good morning, everyone. I'll go over the second quarter operational performance, provide an update on lower well costs anticipated for the second half of 2012 and touch on guidance for the remainder of the year.

The quarter is characterized by record liquids production and successful expansion of our Eagle Ford development program in areas beyond Gates Ranch. During the quarter, capital expenditures were $171.4 million for a total of $304.1 million spent through the first 6 months. We drilled 20 gross Eagle Ford wells and completed 15. Our average daily production for the quarter was 33,400 barrels a day equivalent. Production was up 25% from the prior year and down a modest 1% sequentially. The year-over-year growth driver continues to be the Eagle Ford trend, averaging 32,200 barrels a day equivalent and up 49% from the prior year.

The slight decline in total production for the first quarter was due to the previously announced Lobo and Olmos divestitures, the majority of which closed on March 23. The first quarter production included about 2,400 barrels a day equivalent from the divested properties. A second tranche of divested properties closed on June 29 for 800 barrels a day equivalent leaving 300 barrels a day of additional sales properties to close by the end of the third quarter. Sequentially, Eagle Ford production increased by 6% and was impacted by the previously announced startup timing of the Klotzman truck terminal. Seven of the 15 wells completed in the quarter were in the Karnes Trough area and therefore made little contribution to the quarter. Production in the quarter was also impacted by the need to shut in wells as part of our normal completion process associated with closely spaced pad development. As we've mentioned on previous calls, production growth this year is expected to be back-end loaded. A contributing factor to this is our active management of our pad drilling and stimulation operations. When developing contiguous, closely spaced pad locations, like we're doing at Gates, Briscoe and Karnes Trough, we must first drill a sufficient number of wells ahead of the fracturing stimulation crews to ensure the stimulation doesn't interfere with drilling operations. Also, we're seeing the benefit of shutting in wells adjacent to offset fracturing activities. We are also leaving newly stimulated pad wells shut-in, sometimes for as long as a month, until the next wells in the pattern are completed. While all of these things impacted second quarter volumes, we saw decent growth in the quarter and believe we will see that accelerate in the back half of the year.

Liquids production continues to be a big part of our overall growth story and averaged a record 19,700 barrels per day for the quarter, constituting about 59% of total production using a 6:1 equivalency ratio. More recently during the month of July, total production averaged 35,000 barrels a day equivalent, which equates to a 9% increase versus the second quarter average rate after adjusting for divestiture volumes.

Also, July liquids constitute about 61% of production with crude oil now representing half of total liquids. Please refer to Slide 7 in our presentation deck, which shows Rosetta's historical quarterly production growth and the significant contribution from our outstanding Eagle Ford results over the last 9 consecutive quarters.

In the Eagle Ford, we ran 2 rigs at Gates Ranch, 2 rigs in the Karnes Trough area and 1 rig at Briscoe Ranch during the quarter. As I mentioned earlier, we completed 15 wells in the second quarter, which brings our total for the year to 27 completions, which is about on pace for the full year when compared to our annual guidance of $640 million and 60 completions.

On last quarter's call, I talked about the development program in our highly productive Karnes Trough area and the need for some very significant oil-handling facilities, as well as a large trucking terminal to move the product to market. During the last week of July, our new Klotzman oil terminal was placed in service and is designed to handle peak oil rates of 10,000 to 12,000 barrels of oil per day. And Klotzman multi-well pad completions started in the late quarter -- second quarter rather, and the new wells are now flowing directly to sales. We are also staying ahead of our facility infrastructure needs at Gates Ranch, where a typical production facility costs about $4 million, serves about 15 to 20 wells. By year end, we will have 9 facilities in operation to handle production at Gates Ranch.

At the end of the second quarter, 19 drilled wells were awaiting completion, 17 of which were drilled during the second quarter. We also had 8 producing wells temporarily shut-in for offset fracturing activity. Rosetta plans to complete 16 Eagle Ford wells during the third quarter and continue to operate 5 rigs in the play, including 2 rigs at Gates Ranch. By year end, we will have 37 Eagle Ford wells drilled and awaiting completion, consistent with the pad development approach I just outlined.

In the Eagle Ford trend, we're seeing downward pressure on both drilling and completion costs, primarily due to increased availability of services. We've been working with our suppliers and total well costs are now expected to be down from $0.5 million to $1 million per well. During the second half of the year, we expect Gates Ranch, Briscoe Ranch and Central Dimmit area well costs to average between $7.5 million to $8 million per well, down from our previous range of $8 million to $8.5 million per well.

In Karnes Trough, well costs are expected to average between $8.5 million to $9 million per well, down about $1 million per well.

Moving to the Southern Alberta Basin, we continue to -- I'm sorry, we completed the drilling of our exploratory 7-well horizontal program. The final 3 wells were drilled during the second quarter. In total, 5 of the 7 drilled wells were completed. Three were open-hole completions with packers and sliding sleeves, and 2 were cased-hole completions utilizing perf-and-plug techniques. Average initial production rates for the 5 completed wells range from 50 to 403 barrels of oil equivalent per day. John Clayton will provide additional color and some comments on the Southern Alberta Basin exploration activities.

As John Hagale mentioned, we've updated expense guidance for the year. Direct LOE is now expected to average $2.15 to $2.20 per BOE for full year 2012. Direct LOE averaged $2.50 per BOE for the quarter, that's down 4% from the quarter a year ago and up 31% sequentially, a result of the increased support required for the startup of multiple concurrent development operations in the Eagle Ford, increased oil handling and growth in the number of production facilities. Through the first 6 months of 2012, direct LOE averaged $2.20 per BOE, down 38% from the first 6 months of 2011. For the remainder of 2012, we anticipate direct LOE to average about $2.10 per BOE.

We are reaffirming our $640 million capital guidance, as well as our previously provided annual production guidance. We are choosing to utilize the cost savings we're seeing to set up the company for 2013. We will drill about 7 to 10 more wells than previously planned in order to support pad development. We are also getting ahead of facility construction to ensure we continue to deliver production without facility-related delays. For instance, at Gates Ranch, by year end, we will have 9 central production facilities online with each facility capable of handling 15 to 20 wells each. A typical facility will only be at about 60% of full utilization at year-end 2012. These should provide plenty of flexibility going into next year.

We are still -- we still expect to produce between 35,000 to 38,000 barrels of oil equivalent per day for full year 2012 with an average liquids percentage of 60% for the year, despite having some pattern wells shut-in periodically due to offset fracturing activity. Exit rate guidance is also unchanged and is expected to range from 39,000 to 44,000 barrels of oil equivalent per day with liquids constituting about 61% of total production.

We also are anticipating some significant growth in reserves for the year with our reserve replacement ratio expected to be about 450% at year end. Specifically, at year end, we expect reserve additions, excluding the effects of revisions and asset sales, to range from 58 million barrels equivalent to 63 million barrels equivalent.

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 several activities within asset development. It's been a very busy quarter for us, and my comments will focus on the following: first, new well spacing at Gates Ranch and our estimate on well recoveries; second, new well spacing at Briscoe Ranch and our estimate on well recoveries there; third, our initial estimate for well recoveries at Klotzman; and finally, an update on our Southern Alberta Basin activities and our decision to suspend activity on that exploratory play.

Turning to Slide 9, let's review our continued progress at Gates Ranch specifically related to our view of the proper well spacing, something that we have been working on now for more than 2 years. As I mentioned during the first quarter call, we were working really hard and looking at whether or not our current 65-acre well spacing was optimum. As you know, we have wells spaced on the property from 50 acres in size up to our original 100-acre well spacing. Nearly 1 year ago, we implemented pilot programs that have been gathering data on 50-acre multi-well pads, as well as 65-acre multi-well pads. These 50- to 65-acre spaced pilot wells continue to perform in line with our original 100-acre spaced wells and have not seen interference. Based on these consistent results, supporting pressure data and internal reservoir simulation, Rosetta is now drilling its Gates Ranch program with wells spaced 475 feet apart or on roughly 55-acre spacing. With our new well spacing assumptions, we believe Gates Ranch will be fully developed with 428 horizontal wells, a 32% increase versus the 325 wells projected at the previous 65-acre spacing. Of the 428 wells under our new development scenario, 356 wells remain to be completed at the end of the second quarter, which means that since our discovery well back in the fall of 2009, nearly 3 years ago, we have now developed 17% of the ultimate development we anticipate to occur on the ranch. Based on our new evaluation and new well spacing pattern, the gross estimated ultimate recovery, or EUR, of Gates Ranch is now roughly 715 million barrels of oil equivalent or 1.67 million BOEs per well. This new estimate is 32% higher than our prior estimate of 543 million BOEs from the 325 wells previously planned. It's truly a remarkable asset.

Now let's turn to Slide 10. During the second quarter, the company began development at Briscoe Ranch with the drilling of its first 3-well pad and completion activity is underway. We've been closely monitoring the Briscoe Ranch discovery well since its completion in the fall of last year. As a reminder, Briscoe Ranch is located 5 miles north of Gates Ranch and therefore is in the higher liquids content window of the play. We now feel we have seen enough performance data to provide a type curve for the area, as well as make a call on the development well spacing. Based on the production and pressure data, the gross EUR for Briscoe Ranch is approximately 890,000 BOEs per well, of which 24% is oil, 36% is natural gas liquids and the remaining 40% is residue gas. The well spacing for this asset will be 425 feet between wells or 50 acres per well. This spacing is tighter than our original thought of 65 acres. However, based on the data we have collected in this area of the play, we believe that 50-acre spacing is very prudent and consistent with the higher liquid content relative to Gates Ranch. Based on our current type curve and current well spacing determination, we have roughly 68 wells on our development schedule for Briscoe Ranch. This well count is up from our previously planned 58 wells. These 68 wells have an estimated ultimate recovery for the property of slightly more than 60 million barrels of oil equivalent. From an economic standpoint, one typical Briscoe Ranch well has before income tax PV10 of $7 million after capital recovery. This assumes a flat oil price of $85 per barrel.

Needless to say, we're extremely pleased with this area and have entered into full development mode.

Now let's move to the Karnes Trough area. On Slide 11, we show the new type curve for the Klotzman wells as we promised you we would last quarter. The average gross EUR for Klotzman is approximately 665,000 BOEs per well, of which 68% is black oil, 13% NGLs and 19% residue gas. The lease has phenomenal economics with the wells paying out in approximately 6 to 9 months. The Klotzman wells have a before income tax PV10 of approximately $12 million per well, again after capital recovery. This also assumes a flat oil price of $85 per barrel.

During the second quarter, 4 Klotzman oil wells were drilled and 6 were completed for a total of 8 wells currently on production. We plan to drill and complete all of the remaining Klotzman locations prior to the end of this year.

Now let's discuss our decision to suspend activity in the Southern Alberta Basin. During the quarter, we concluded work on our 7-well horizontal program. Of the 7 horizontal wells drilled, 5 have been completed. Of those 5 completions, the initial 3 were completed in late 2011 as open-hole completions with swell packers and sliding sleeves. As a reminder, these 3 wells averaged initial rates ranging from 104 barrels of oil per day equivalent to 403 BOEs per day. The most recent 2 completions were cased-hole completions with perf-and-plug techniques. Those wells averaged 50 to 205 BOEs per day. As I've shared on past calls, we were targeting 30-day initial production rates of 250 BOEs per day and an EUR of 185,000 BOEs. Based on the results to date, which are below the targeted type curve, we have decided to suspend all capital activity on this project. At this point in time, we have no plans to complete the remaining 2 horizontal wells. In the second quarter, we wrote off approximately $83 million of unevaluated cost for these Montana properties, which will increase our DD&A rate in the second half of the year by $0.49 per barrel. Currently, Rosetta Southern Alberta Basin position has leases and lease options, which will begin to expire no earlier than January 2014.

Before I turn the call over to Randy, I would like to turn your attention to our inventory slide, which is Slide 12. We have updated the slide with our new well spacing at Gates Ranch and Briscoe Ranch, as well as activities that have occurred from inception through June of this year. Although we don't show our well EURs on this slide, we have now provided you with type curves in 3 of these areas. Utilizing this data, if you do the math, on a gross basis, we have more than 3/4 of 1 billion barrels of oil equivalent that will be recovered from Gates Ranch, Briscoe Ranch and the Klotzman area of the Karnes Trough alone. Additionally, you can see from this slide, that as of midyear, we have roughly 900 well locations remaining to develop in Eagle Ford, of which 80% are in the liquids window of the play. We have said before that we are a company that likes repeatable inventory, and we're extremely pleased with what our portfolio has to offer our shareholders.

Finally, Jim and I would like to thank our technical organizations for the tremendous job they do on a day-to-day basis for our company. With that, I'll turn the call back to Randy.

Randy L. Limbacher

Thanks, John. I hope our comments this morning have given you a clear perspective on our second quarter results and what we are working on for the rest of the year. Let's turn the call back to the moderator, so we can take some of your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Leo Mariani of RBC.

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

I saw that your oil price is up pretty significantly in the second quarter relative to WTI. You guys averaged somewhere, I think, around 97%. It had been lower previously. Anything sort of going on there in terms of -- I know you guys were looking to start getting your oil sold at a more of LLS. Did that kick in on the second quarter? Because I thought that was more of a second half of this year.

John E. Hagale

This is John Hagale, and we did guide you earlier -- on an earlier call that oil prices would get better in the second half, and we got some of that benefit a littler earlier than we thought we did. So in the past, we've said 70% WTI less around 10%, 30% LLS around -- less around 10%, and we said that would be more back-end loaded, that was the full year guidance. And what we saw was even though the pipeline is not in place yet for LLS pricing, we're starting to get some better pricing. Some of it is the fact that the Klotzman oil is lower gravity, some of it is the fact that the Klotzman oil is a little closer to the premium markets. So I would say I wouldn't change our annual guidance, but what I'd tell you is we've got it a little sooner than we thought we're going to.

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

Okay. Just in terms of Klotzman oil, I know you guys talked about getting 7 wells online in the second quarter. Did you see a lot of production benefit in the second quarter from that? Because I know the facility just started to come on in July. I guess, what I'm really trying to get at, should we see a big surge on those wells in terms of oil production as we get into the third quarter? Or did you get much benefit in the second quarter? So any color you had around that.

Randy L. Limbacher

We did complete 7 of those wells in the second quarter, but they didn't impact second quarter production very much, and they are online now. We are still going through the usual startup things that you go through with the new facilities, so we are right restricting those wells. But yes, we expect them to be bigger contributors in the third quarter than we saw in the second.

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

Okay, that's great. And I guess, in terms of your CapEx, you talked about $640 million for the yearly budget is unchanged. Does that include any dollars for sort of the new couple of exploration plays that you guys identified there? And does that also include incremental well activity this year in the Eagle Ford? I'm assuming maybe that the lower well costs are allowing you to drill more with the same amount of dollars. Any color you had around that?

John D. Clayton

Yes, Leo, this is John. On the first part of your question, yes, I think we can do our new ventures type activities that we're doing within the $640 million, one, based on shutting down our Southern Alberta program, and then two, the well cost savings we're seeing in the operations group. If we were to do an acquisition, obviously, that wouldn't be included in the $640 million case. As far as the activity in the Eagle Ford, I think we're still on pace for about 60 completions this year although we're going to drill quite a few more wells than we originally planned. I think we actually go out the year with somewhere close to about 30 wells that were drilled but not yet completed and that's just to get ahead of our frac crews out in the field.

Operator

Our next question comes from Welles Fitzpatrick of Johnson Rice.

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

Sorry if I missed this, but if I remember correctly, you guys were renegotiating your completion contract this summer. Did those new completed well costs you listed -- are those under the new contract? Or are those more efficiency-based savings?

James E. Craddock

Welles, this is Jim. What I would say is we took a hard look at all the different aspects of well cost, and so the savings that we've talked about really kind of are across the board. Yes, there's some lower stimulation cost embedded in that, but we're also seeing lower cost on things like drilling mud, cement, coil tubing, wireline, so it's really across the board. And it's really a function of the fact that we're seeing a lot more service availability in the South Texas area now, which is very helpful.

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

Okay. And on the Briscoe Ranch spacing, gone from 65 to 50. Obviously, you haven't done quite as much drilling there as you have in Gates. Is there any chance of tweaking that tighter moving forward? Or are you guys pretty confident given it's proximity to Gates that, that 50 is going to be kind of the final spacing?

John D. Clayton

That -- it's a tough corner to get backed into because we've learned quite a bit at Gates, and we are using some of the simulation results we've done at Gates for the last couple of years on what these rocks are actually draining. We show you guys production, we talk about pressures, but the big driving force behind how we're looking at these rocks is some of the simulation our groups have done on what they're actually draining. We're actually seeing drainage patterns at Gates Ranch in the 30- to 50-acre type range, and that was really more a leading factor on -- we know the reservoir's going to perform in tighter spacing as you move north. Briscoe's 5 miles to the north of Gates Ranch, it is more liquidy. We made the original call now at 50-acre spacing. I hate to tell you can't go down any further until we probably get a few more pads on and then see how the rocks treat over time. But we have 68 wells to drill. That would -- with 1 rig running up there, that's probably about 5 -- 4.5 or 5 years of activity. So don't back me into a corner and hold me to that because it's still pretty early.

Operator

Our next question is from Neal Dingmann of SunTrust.

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

Just maybe, Randy, for you or Jim, just wondering -- or for you, John, just wondering on well cost. You continue to bring those down just dramatically. And just wondering -- because when you look at those -- a couple of things around that. Obviously, one, on the efficiencies, just wondering how much better that can get to bring cost down. And then secondly, I know you had a large service contract. I think you are renegotiating or in the process and just wondering, with that, is that another long-term contract you would sign into or are you're going to more day-to-day? I'm wondering, if so, would that bring cost down even more or if it already has?

James E. Craddock

Neal, this is Jim. I guess I'll take it in 2 parts. First of all, what I would say is in terms of predicting the future, that's difficult. We do work pretty hard on the efficiency side. We're still using 3-well pads. We haven't done the super long link laterals, but we are pilot testing different aspects of that technology. So as we move forward in time, we do hope to see increased efficiency. One item that we're looking at is larger than 3-well pads, what kind of savings can that provide. So we'll be looking at some of those things to be moved through the rest of this year into next year. As far as the stimulation contract, I don't want to get into a lot of detail about that. I will just say we work with our service provider there, and so we have seen some of the improvement is cost because they work with us on that, and we think that's going to last us well into next year.

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

Okay, got that. Great answer, Jim. And just wondering now a couple of things. One, if you look at Pearsall, it kind of hurt, I guess. It seems like there's 2 different camps. Some people think -- looking at them more actively, others are taking more latency. Just kind of wondering what camp you would put yourselves in.

John E. Hagale

Yes, this is John. I'll field that one. We've -- we started to get some activity around our Gates Ranch, not by us but by offset operators that we're watching. We've also -- we spent a lot of time looking at the Pearsall. We do think we have some of our acreage that would be more into the liquids window. We're not in any rush on that, but it is something that we have a focus on right now.

Operator

Our next question comes from Irene Haas of Wunderlich Securities.

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

If I may slip in 2 questions. First one really has to do with -- recently, EOG has delivered some really monster well in sort of the Karnes Trough area. My question for you is, is there something sort of unique with the rock, the geology? And can it be kind of replicated by folks like yourself? Second question is sort of your new venture area. Since you've all spent a lot of time in Farmington, I'm wondering if there's someone based in Mancos Shales of interest.

John D. Clayton

I'll tackle -- I guess, I'll start with the second one. We're not focused on the Mancos in Farmington right now. We've got some other areas we're focused on that we think probably fit our portfolio of kind of what we target. The first question though is we'll kind of take that one personally. I think we've got a bunch of monster wells in our portfolio. Now EOG is doing a pretty phenomenal job. We haven't seen rates as large as the ones they recently announced. But one of the things we focus on is repeatability. And with that, we like tight distributions of well count. We'd love to have monster wells, but I think we like the repeatability their assets are giving us. I wouldn't look for us to drill a monster well at Gates, although we are early in the development of Gates and we probably haven't drilled the best well yet. So I'll leave it at that. But it's a good question. EOG is a fantastic operator and they've got some stellar results, but we think ours are pretty good, too.

Randy L. Limbacher

I think also implied in that is, no, we don't know what they've done differently or if there is something different in the rocks that have caused those differences. So it's intriguing to think about and consider, but I don't think we know any differential information on that.

Operator

Our next question comes from Pearce Hammond of Simmons & Company.

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

Jim, just to clarify. You said on the call you're going to utilize some of the cost savings in the wells and drill 7 to 10 wells more than previously planned and that's this year?

James E. Craddock

Yes, Pearce, that's right. So we'll end up -- I think we'll end up with about 85 drilled wells. We entered the year with an inventory of not completed wells, so that will grow. And we'll have about 37 wells, I think is the count, drilled but not completed. When you think about 3 pad development -- closely spaced pad developments happening simultaneously at Klotzman, Briscoe and Gates, it's really only about 12 wells ahead of the frac crews in each of those locations. So it's not -- it sounds like a lot but that's really what's going on as we need to get ahead of the frac crews in each of those areas so we don't have any interference between drilling and completion.

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

Great. And then a follow-up. The Klotzman truck terminal 10,000 to 12,000 barrels of oil a day capacity. Is it your anticipation that you'll utilize all of that capacity? Or will you have some other producers utilizing some of that?

James E. Craddock

It's -- Or I guess, as far as other producers, it's solely for our wells there. But keep in mind, we've only done the first, I think, 8 wells of that area, and so we've got another 7 wells to complete at Klotzman later this year. And as far as whether we will or won't utilize all of that, I'm not going to speculate yet. We'll see how those next wells do, but we felt like we needed to have sufficient capacity to move that oil just based on the strength of the wells.

Operator

Our next question is from Michael Hall of Robert W. Baird.

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

I guess, a couple on my end. First, in Briscoe, if I look back at some of the old presentations, as I recall, you had, I think, the first well in Briscoe tracking nicely ahead of the 1.7 million BOE type curves. I'm just curious, as you're modeling down the 50-acre spacing, are you assuming some reduction in per-well recovery? Or I should say per-well recovery or per-well productivity? I guess, what's the thought there?

John D. Clayton

Yes, this is John, Michael. When we showed that slide, we were very reluctant to put an EUR on the Briscoe curve, and I think, at the time, we said it's too early to make that call. It is in a higher liquids area but we wanted to at least give you guys a feel of why we were excited about it. That liquids area, which you could see on the type curve we've now published for Briscoe Ranch, declines a lot steeper than the Gates Ranch properties that we have. Hence, the lower EUR. But if you look at the liquids content where we're getting the value out of Briscoe is, although it's got a lower EUR, it's got a higher liquids content. So early on, yes, we've put it on a slide against our Gates Ranch curve to talk about our enthusiasm with at least the initial results. But from a value standpoint, we're getting more liquids in that area but the EUR is the type curve that we published today, and I think we're going to stick with that until we get a few more pads on and see what they're doing.

Randy L. Limbacher

Yes. That is -- that's kind one of the dangers of use. I mean, we all do it, we all want to put that initial rate out there and that does give you some idea of a starting point. But that is exactly why we wait until a little later on to actually put an EUR estimate in place as opposed to just saying based on this initial rate, you would expect this recovery. There's a little bit of a dangerous viewpoint of doing that.

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

Fair enough. I guess it makes sense. Higher prices [ph] , higher liquids content. I'm just curious, probably some additional acres to delineate. I think you highlighted it in the final slide in the current deck here. Any thoughts on timing of getting some of that delineated?

John D. Clayton

Yes. This is John again. I'll address that. 3,500 of that is non-operated. It's our only non-operated piece. We actually -- not we, but the operator out there and we participated has drilled 10 wells on a 40,000-acre ranch. And that's not a whole lot of wells for us to declare delineation yet, strictly because although it's 10 wells, we have a 7% interest on a 40,000-acre ranch that's operated by 2 companies. So there is activity. I think they've got another dozen or so wells that are planned out there for the tail end of this year. So we're getting activity on a non-operated piece, which is 3,500 of it. If you look at the northern or south piece, we have a project that's on our drilling schedule coming up here in a month or 2 that we can get tested. And then the remainder is over in Gonzales County and we're kind of watching offset operators on that property.

Operator

[Operator Instructions] Our next question comes from Jeff Hayden of KLR Group.

Jeffrey Hayden

Just first on the -- to make sure I heard right. Did you say that oil production currently counts for only 50% of your liquids volumes?

James E. Craddock

Yes, Jeff, that's correct for the July update. It's half of the total liquids volumes now.

Jeffrey Hayden

Okay. And kind of given that and the stage that the Klotzman wells are in, would you guys be willing to provide some color on kind of how you see that ratio between oil and NGL kind of moving forward sort of Q3, Q4?

James E. Craddock

Yes, I guess what I would reference maybe is the exit rate. We've provided that guidance and I think we say we're expecting about 61% liquids. And when I look at that on the split, it's again about 50-50 oil and NGLs for the exit rate. So I think what we're seeing now is we believe it will be rather consistent for the rest of the -- of this year.

Jeffrey Hayden

Okay, great. And then just kind of a follow-up on one of the questions about the Pearsall. On most of your acreage, are you holding the Pearsall with the Eagle Ford drilling? Or do you have to drill down for that to hold it?

John D. Clayton

Some of it we will have to drill down for us to hold it. That's a good point.

Jeffrey Hayden

Okay. And then just kind of jumping over to the new ventures. Any idea of when we might get some color on some of what you guys are doing on the new ventures side of things?

John E. Hagale

If we had to do it over again, we probably wouldn't have come out as early on the Southern Alberta Bakken. But I think when we had, it's kind of like we've done on our Eagle Ford. I would kind of look for that type of signal from us. Once we have something that's meaningful to disclose to the public, we'll go ahead and make that disclosure. Anything else is it just gets people excited about stuff that doesn't have a lot of meat on the bone yet. So I would look for us to cultivate these ideas, get some wells tested and to where we had some production to show you guys.

Randy L. Limbacher

And Jeff, I mean, our idea in signaling that these are existing out there isn't to be queued. You always hear people talking about stuff, plays and this and that. I think what we wanted to do is give you some reassurances that this is a part of our portfolio. We're not -- we've got a plan of how we're going to spend the capital and allocate it between looking for acquisitions and new ventures. And we just wanted to give you some reassurances that, that -- those things are really going on right now. And as John said, once we get some results that are meaningful, we will share it but probably not any time in the short term should you expect to see that.

Operator

Our next question comes from Dan McSpirit of BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

Your pursuit of these new concepts under the new ventures group here, should we expect those new ventures to take on a similar risk profile as what we saw with the Southern Alberta Basin that is leasing of raw acreage with little or no well control?

John D. Clayton

I wouldn't say we didn't have well control up in the Southern Alberta Basin. We probably had as much well control there as when the Eagle Ford play started taking off with maybe deeper wells. I think what you could expect though is it's going to be rocks that are resource-rich and with high, high, high degree of certainty that there will be hydrocarbons in them. That was the case when we got into the Eagle Ford. That's the case in the Southern Alberta Basin. And then we'll just try to move as prudently as possible with the lowest amount of capital exposure to see if we can make that resource commercial. If I look at the Southern Alberta Basin, to go into a basin, find a significant amount of hydrocarbons in place and for us to produce oil out of those rocks is quite an accomplishment. Now we're in this business to make money but I think the same time we were doing the Southern Alberta, we were making our entry into the Eagle Ford, which was prior to the Petrohawk announcement. So we're big on repeatability and we're big on low geologic risk. I think we like to put the risk on the commerciality components. That's kind of how I'd look at it.

Randy L. Limbacher

Yes, I think John's point is well taken. I think what you're getting at here is a real good question, is you're looking for what's the risk profile of what you're targeting. And so I look at it to kind of follow the dollars. If you look at when we do our planning around, where our cash flows are going to be like -- looking like in the next 4 or 5 years, we say, "Hey, we're willing to take 10% or so of any given year's capital program and chase some of these higher risk and potentially really high return things to try to find the next Eagle Ford or the next opportunity like that." And then you would look for the remainder of that free cash flow to go for acquisitions of areas that have already been at least somewhat derisked.

Dan McSpirit - BMO Capital Markets U.S.

Understand. And I appreciate the context. And then sticking on new ventures as a follow-up. Is there a contrarian bone or a contrarian view within the group that is -- that may prompt you to look at natural gas-producing assets or rocks that are of the natural gas variety?

James E. Craddock

Well, probably not at this point in time. What I would say is we are always indifferent as to what the product is. What we are looking for is what's the highest margin result and the best economics. And we study the natural gas basin. We continue to look at it. We have exposure in our Encinal area to half a T of opportunities that can be developed when the time's right so we already have some exposure there. But when we look at this space on just pure natural gas, on one end, we think there's probably more upside in natural gas prices than the other commodities right now. But when we look at the pricing of going out and purchasing those assets, we don't think that they have come down in proportion to the decrease that you saw in natural gas. So I would say that's a long-winded answer but I would say now we still think that the gas side of it's priced a little bit too high, and we have pretty good exposure on the dry gas window of the Eagle Ford as well.

Operator

Our next question is from Brian Velie of Capital One South.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

I had a couple of questions, most of which have been answered. But real quick on the well completions in Karnes Trough. I was modeling and kind of expecting somewhere in the range of about 10 for the year. It sounds like you're well ahead of schedule there. I think I just maybe heard you mention that 7 more are planned in Klotzman, specifically on top of the 7 that were done in 2Q. Is that -- is it right to think of that as maybe a little bit ahead of what you had been expecting up until now?

James E. Craddock

Yes, I think that's fair, Brian. We -- I think we originally thought we might get maybe 2 or 3 more done this year, and we think we see a way to get the full complement of Klotzman wells done before year end. That's what we were working towards. So yes, I think based on maybe previous guidance, we will probably not think that we can get that done.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Okay, great. And then I guess that impacts -- it sounds like the exit rate for the oil -- or I'm sorry, liquids mix doesn't change at 61%. But with these coming out a little bit later in the year, is that a number that you expect because of where you are in the schedule right now for these -- that number to continue going higher in '13?

James E. Craddock

Well, I think what you can expect is we reached a point where we're pretty steady state in terms of how many completions are coming from each of the different areas. And so I really feel like the mix we're seeing now should be relatively consistent. And we haven't done a lot of work on '13 yet so I'm not going to declare on that. But again, we start completing a large number of Gates Ranch wells each quarter as well and so that goes into the mix.

Randy L. Limbacher

Yes, there's always going to be some lumpiness in the thing, but I think for modeling purposes, our suggestion would be to stick with the guidance that's out there on the exit rate side. That's going to tend to even out over time. There may be some dislocations in any given quarter, but over time, I think you're going to see some decline on the Klotzman piece as well. So -- and since we have smaller well count there, I think that the guidance is pretty good that's out there.

Operator

At this time, I'd like to turn the call back to management for any further remarks.

Randy L. Limbacher

Okay. Well, thank you. We appreciate your time this morning and getting the chance to update you. We look forward to visiting with you again in November to discuss our third quarter results, and we hope you have a good day. Take care.

Operator

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

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