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Executives

Michael J. Rosinski – Executive Vice President, Chief Financial Officer, & Treasurer

Randy L. Limbacher – President & Chief Executive Officer

James E. Craddock – Vice President, Drilling & Production Operations

John D. Clayton – Vice President, Asset Development

Analysts

Mark Lear – Sidoti & Company

Richard Rossi – Wunderlich Securities

[Phil Pace] – [Chambers Energy]

Rosetta Resources Inc. (ROSE) Q4 2008 Earnings Call March 2, 2009 11:00 AM ET

Operator

Good morning everyone and welcome to Rosetta Resources year-end 2008 conference call. Today's conference is being recorded and all lines have been placed on mute to prevent any background noise.

If you're not able to participate in the conference call, an audio replay will be available from 12 pm Central on March 2, 2009 through 12 am on March 9, 2009, by dialing 888-203-1112, or for international, 719-457-0820, and entering conference code 4262476. A replay of the call will remain online at www.rosettaresources.com for 60 days after the initial call. To access the replay, click on the Investor Relations section of our website and select Presentations and Events.

Prepared remarks will be delivered this morning by Mike Rosinski, Chief Financial Officer and Executive Vice President and Randy Limbacher, Rosetta's President and Chief Executive Officer. Also present on the call are John Clayton, Vice President of Asset Development and Jim Craddock, Vice President of Drilling and Production Operations.

At this time I’d like to turn the call over to Mike Rosinski. Mr. Rosinski you may begin your conference.

Michael J. Rosinski

Thank you. Good morning and thank you for joining us for our year-end 2008 conference call. Before we proceed, I will read Rosetta’s Safe Harbor statement. All statements other than statements of historical fact included in this presentation are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based on current expectations and are subject to a number of risks, uncertainties and assumptions, which are more fully described in Rosetta Resources' Annual Report on Form 10-K, and quarterly reports on Form 10-Q filed with Securities & Exchange Commission.

These risks, uncertainties and assumptions could cause actual results to differ materially from those described in the forward-looking statements. Rosetta Resources assumes no obligation and expressly disclaims any duty to update the information contained herein, except as required by law. By the way, please note that Rosetta has filed its 2008 Form 10-K, which can be accessed via our website under the Investor Relations tab.

Our call agenda for today will include some comments about our full year 2008 financial results. These will be brief because they have been thoroughly addressed in our recent press releases and our Form 10-K. After my comments, I will turn the call over to Randy, who would make quicker run through of our operations and reserves and then summarize our achievements for 2008. Finally, he will discuss our outlook for the business and our operational plan for 2009. After our prepared remarks, we will go to the Q&A session.

Now, I will proceed with our financial review. For the full year 2008 Rosetta reported a net loss of $188.1 million or $3.71 per diluted share, a decrease of $245 million from net income of $57.2 million or $1.13 per diluted share for the same period in 2007. These results include an previously announced non-cash impairment charges and a charge associated with the settlement of Calpine lawsuit. It's important to note that excluding these charges Rosetta would have earned net income of $98.6 million or $1.95 per diluted share, that's a 72% increase, compared to the full year 2007.

Production and revenues for the full year were 147 million a day and 499.3 million respectively. Our annual production rate was up 17% compared to 2007 volumes of 126 million a day and achieved the high-end of our guidance range despite the impact of Hurricane Ike. Our 2008 revenues were up 37% compared to $363.5 million in 2007 driven both by higher volumes and higher average commodity prices.

Average realized gas prices in 2008 increased to $8.81 per Mcf from $7.61 per Mcf in 2007. Total revenue in 2008 was reduced by $18.7 million due to effects of natural gas hedging. For the full year 2008, LOE was $55.7 million or $1.04 per Mcfe about flat compared to $1.03 per Mcfe in 2007. So, we held the line on a unit basis for that important metric in 2008 despite significant cost pressures throughout the industry during much of the year. As Randy will discuss later this continues to be a focus area for us in 2009.

Depreciation, depletion and amortization was $198.8 million reflecting a DD&A rate of $3.71 per Mcfe. 2009, we expect this rate to be about 20% lower than it was in 2008. General and administrative costs were 52.8 million in 2008. This included some non-recurring item such as severance costs and about $12.1 million of legal cost associated with the Calpine lawsuit. This item also included $7.2 million in non-cash stock compensation expense. We generated about $345 million of cash in 2008, while capital expenditures were $334.5 million. In other words, even in a frailty environment we lived within cash flow.

Now, I’ll make a couple of quick comments about our cash and liquidity situation. Rosetta ended the year with $42.5 million of cash on hand and a borrowing base that was reaffirmed in the fourth quarter of 2008 at $400 million. Between cash on hand and the undrawn revolver, we have liquidity of about $215 million. In the next several weeks, we will be in the process of affirming our borrowing base once again. We'll update the marketplace when the outcome of our determination is known. Before I leave this topic, I want to make one more point as Randy will discuss in a moment like many others in our industry Rosetta has adopted an operational plan to live within cash flow on our capital spending for the year.

One of the keys to this plan is to have an accurate process in place for tracking and forecasting our cash balances. We have such a process and will use it on a continuos basis. Given the front-end loaded nature of our 2009 capital spending and in fact that we'll settle some late 2008 capital activity in this yea's first quarter. We would expect our cash balance to dip in the first quarter and then rebuild given our current outlook for 2009 spending.

Finally, the company’s hedge position is unchanged. The company has fixed price hedges as follows. For 2009, 52 million a day in our hedge at an average price of $7.65 along with 10 million a day for 2010 at an average price of $8.30. Additionally, the company has entered into costless collar transactions for 5 million a day for 2009 with an average floor price of $8 and an average ceiling price of $10.05. Now I would like to turn the call over to Randy for some 2008 operational highlights and comments about our 2009 outlook.

Randy L. Limbacher

Thanks, Mike. I am going to start with a very quick run through of our operating areas and please refer to our disclosure documents for some more detail. During 2008, the company drilled a 184 gross and a 152 net wells with a net success rate of 89%. The majority of this drilling activity took place in the DJ Basin and South Texas, but we had programs in all of our core areas. Production averaged to 147 million a day up 17% compared to 2007.

Annual production volumes grew in the Rockies, Lobo trend, Texas State Waters and Other Onshore areas. If we exclude the Gulf of Mexico and State Waters from those numbers our remaining core areas were up about $13 million a day or 12%, year-over-year. Sequentially, in the fourth quarter versus the third quarter, our total volumes were about flat, but the core areas were up about 6 million a day due to volume increases in San Juan Basin and California. So, again we think this demonstrates the continued strong performance of the going forward assets.

I should note that we are currently producing between 155 million and 165 million a day, which included a benefit of the year-end acquisition volumes. Our momentum coming into 2009 is strong. Now, I want to step through the areas beginning with California. In California, the company drilled 14 wells, 13 were successful. Average net daily production in 2008 was 44 million a day flat to 2007. The company has a high-operated working interest in the Rio Vista Gas Unit, where we are currently testing several unconventional concepts in various horizons.

Recently, we announced preliminary results from a tight Capay recompletion program. And we are very encouraged by those early results. We conducted four recompletions and completed two other wells in this tight Capay sand. The six wells are producing an average of about 650 Mcf a day with two of those wells making over 1 million a day. These are very profitable and efficient pieces of business given that the recompletions cost between $500,000 to $600,000 per well. And our goal for the year is to continue monitoring the initial pilot program and delineating the play across the entire Rio Vista Gas Unit, which is a pretty sizable acreage position.

And I would also point out we don’t have any of this resource potential accounted in the inventory numbers that we are going to go through in a just a minute. We had a very busy year in the Rockies in the DJ Basin in Colorado, we have a majority working interest and about a 111,000 net acres with a 154 square miles of 3D seismic data. In 2008, we drilled 76 locations, of which 70 were successful, and identified 500 additional drillable locations on these lands.

Average net daily production for the DJ Basin was 7.6 million a day up compared to 2007. We drilled successful delineation wells in Duke North, Duke, and Duke South that will add to the production already established in the Republican River, Vernon, South West Wray, and Sandy Bluffs areas. We also see additional potential in the DJ asset by expanding our inventory of 40 acres spaced wells as well as from 20 acre down spacing. Late in 2008, we initiated a 20-acre pilot test in the DJ Basin and we are currently monitoring the results there.

Also in the Rockies, we added our San Juan Basin position and added two new areas, one producing and one perspective. In San Juan, Rosetta purchased a 50% working interest position from Petroflow Energy in the second quarter. We drilled 14 coal-bed methane wells on our position all of them were successful. And for the year, our average net daily production from the San Juan was 4.3 million a day. We’ve identified 17 drillable locations on our acreage and we also have 8 wells that have been drilled that are pending completion.

In the fourth quarter of 2008, we acquired producing properties in the Green River Basin of Wyoming. This deal consisted of a 90% working interest and a 1,280-acre position on the Pinedale Anticline with net production of approximately 7 million a day equivalent. Recently, the company acquired the remaining 10% and operatorship of this position.

In the Alberta Basin, we acquired two five-year exploration options from the Blackfeet Nation that were announced at year-end. These are options give us the opportunity to lease approximately a 100,000 net tribal acres in each option that is prospective for the Bakken Shale. In total, the company has approximately 230,000 net acres of exposure in the play. The Bakken Shale in this basin is shallower and more normally pressured than the Williston Basin, Bakken but it has all the other hallmarks of being a significant hydrocarbon resource.

Previously drilled vintage wells and drill stem test data confirmed the presence of movable wells in this play. We intend to drill two tests in this play in 2009. In South Texas, Rosetta drilled 58 wells in the Lobo trend with 48 successful on our 118,000-acre position. During the year, we acquired an additional 10,000 net acres in the Lobo for future prospects. Average production for the Lobo was 46 million a day, which is up about 10% when compared to 2007.

In the Perdido trend, seven wells were drilled all of which were successful and their production averaged 8 million a day in '08. In December, we successfully added to our position in South Texas, we acquired producing properties consisting of a 70% working interest located in the Catarina field with net production of approximately 5 million a day. We also acquired a 35% interest in a significant acreage position in the area that is prospective for the Eagle Ford Shale.

At the end of the year, our Eagle Ford Shale position was 25,000 net acres. We recently tidied an operated vertical well in the play and we're currently evaluating our log and core data from that well. We set this well up to drill lateral in the future and we're also currently partnered on a non-operated vertical well and we plan to drill another operated well this year to further delineate the play. It's really too early to declare any type of results, but we're very encouraged and we have considerable running room if our test wells are successful.

Finally, last year in the Texas State Waters production averaged 12 million a day, we drilled four gross wells of which three were successful. In the Gulf of Mexico, the company owns working interest in 12 offshore blocks with approximately 36,000 net acres. Our average net daily production from these blocks was 12 million a day. By year-end all shut in volumes from Hurricane Ike had been restored and these non-core properties as we've mentioned in the past are identified for potential sale in 2009. During 2008, we added approximately a 105 Bcf of proven reserves the highest level of adds in our history and an almost 200% reserve replacement rate. These adds were comprised of 40 Bcfe of organic additions and 65 Bcf added from acquisitions and the completion of the Calpine transaction.

On additions alone our reserve replacement cost was $3.16 per 1000 for 2008, a nice improvement for the company. We ended the year with total proved oil and natural gas reserves of 398 Bcf equivalent, this consisted of 377 Bcfe or 95% natural gas and 3.6 million barrels of crude oil, condensate, and natural gas liquids. As you already know, our [exact] reserve balance reflects the impact of our previously announced downward reserve provisions of 72 Bcfe, 64 Bcf of those were performance related revisions largely in the low pressure zones in California as well as some in the Lobo play.

The company only recorded 8 Bcfe of downward revisions due to lower year-end prices. We have previously been through these numbers with you. It was a disappointment to have to take these adjustments, however I can give you comfort that ensuring not only the growth, but also the quality of our reserve base is one of management's primary value creation objectives. The fact that of Rosetta's total year-end 2008 proved reserves, 82% are proved developed and 18% are undeveloped is proof of the importance to us of having a quality reserve base.

Perhaps as important as our reserve additions were our additions to project inventory and identified resources. We more than doubled our drilling inventory to a 1,158 projects. Last year at this time, we had about 470 projects in inventory. Including proved undeveloped reserves, this represents resources of approximately 575 Bcf on a net unrisked basis and about 300 Bcf on a net risked basis. So, I think this inventory fits us up nicely for possible growth in future years.

Now I want to move on to some more global comments. First put some perspective on the year Rosetta just completed. It was a transformational year for our company and while I think about how we began 2008, and then how we ended the year it looks like night and day difference and let me run through some of the significant milestones. First we settled Calpine that was a huge distraction and a significant overhang on how we're perceived externally, that's behind us and it really clears the way for us to control our plans and programs as a company.

Next, we initiated a strategic shift to become a resource player. Just a year ago, we were kind of tapping the breaks on our capital spending and conventional high decline rate areas like the Texas State Waters and offshore properties. As the year progressed, we took numerous steps to further drive this change. We staffed and organized our workforce to put an unconventional lens on our existing portfolio and as I noted, we've got a high working interest and operatorship in many of these areas, so we can control the technical evaluation as well as the program pace.

Our studies were commissioned to accelerate inventory generation as well as trade and advantage in expanding our position through leasing and bolt-on acquisitions. While our strategy shift will take time to implement, we offer clear proof that it yielded results in 2008. Our project inventory is almost 2.5 times higher than it was a year ago. We added producing properties in San Juan, South Texas and the Pinedale Anticline with lower decline rates and upside for the future. We identified and initiated testing of some unconventional concepts in places like the Sac Basin and the DJ Basin. We entered two new emerging plays the Bakken in the Alberta Basin and the Eagle Ford Shale in South Texas.

These unconventional concepts are not included in our project inventory today, yet they expose us to unrisked upside potential of about 1.3 trillion cubic feet equivalent. Recall, we have said in the past that our goal was to identify and possibly test four to five of these ideas per year from either existing or new positions. We fully expect one or more of these prospective plays to turn into significant resource potential for Rosetta in the future. And Rosetta is of a size where success in one or two of these ideas could be very leveraging.

Finally, we achieved countless smaller, but impactful wins throughout our company and improving our ability to execute our business. For example, we developed inventory systems and procurement programs that are essential for establishing repeatable programs. It was a good year for our company and I sincerely want to thank those of you, who stuck by Rosetta during this transformational year especially our employees. We have much to be pleased and proud about. However, it cannot be ignored that these achievements are somewhat overshadowed by the broad economic downturn.

And now I want to address a little bit about how Rosetta intends to manage through this down cycle. Really, our behaviors and actions are going to be guided in five key ways. First of all, we are going to continue to act rationally, if the current prices are lower, there is in our view a very little that industry or Rosetta should be drilling and we are acting accordingly.

At this time, we are only active in our most profitable programs namely South Texas, where we currently have a two-rig program underway and California where we have recompletion projects identified. These two areas comprise over two-thirds of our volumes and command premium prices. We are fortunate and that much of Rosetta's acreage is held by production, so we are generally now under pressure to drill to save leases this year. Our high working interest and high level of operatorship are also an advantage as we are not as likely to be drilled out of significant positions by other operators. So, we have the advantage of being able to hold onto our inventory until commodity prices recover, service costs contract, or both.

Second, as Mike already mentioned we intend to live within cash flow on our organic capital spending for the year, and we think that's not only a rationale it's prudent. In order to preserve our liquidity, we have curtailed our spending quite dramatically compared to our historic levels. The challenge of this discipline but flexible approach to capital spending is that it takes, that kind of makes volume forecasting difficult especially this early in the year. We know we need to give you a way to think about our volumes for 2009. So, let me try to walk through it.

Let’s start with where we are now which is we are making about 155 million to 160 million a day. So, in the case where we only spent organic capital at the level that we are currently contemplated and we do not either make an acquisition or ramp up organically later in the year, we would expect to see annual volumes decline about 10 million a day on a full year basis. Then if we sell the offshore and State Waters assets we would be 15 million to 20 million a day lower depending on the timing of any of those asset sales. But I think it's real important that you see this is as the low case for the year.

Let me emphasize, at current prices and at our current rate of spending, we would expect to modestly build cash during the year, in addition to generating possible sales proceeds. So, the analysis that I just step through does not include the benefit of deploying this excess cash toward ramping up our organic program or doing any bolt-on acquisitions as the year plays out. Once again the factors that would cause us to adjust our spending and volume guidance would be a recovery in prices, contraction and service costs and the availability of the proceeds from the possible divestitures.

Third, we are going to intensify the study of our assets and focus on generating inventory, if there is a silk lining in the downturn, it is that we can devote more attention to performing resource assessments in 2009. I think the Sacramento Basin is a great example, where we are doing that, we've got 16 stacked pay intervals, we are mapping each of these and testing some concepts there such as the tight Capay program and later in the year, we expect to test another similar interval.

So, by successfully marrying up a couple of these concepts, we could turn this into a very economic drilling program with running room. In the DJ Basin, we will hopefully conclude our 20-acre in-fill pilots, so we’ve got drilling potential identified when the market terms and we also have other prospective horizons to assess. In San Juan, we have about 18,000 acres to optimize and we have the Bakken Shale in the Alberta Basin that we expect to begin testing this year. In South Texas, we’re continuing to identify inventory on our Lobo acreage position, but in South Texas we also believe the Eagle Ford Shale program has the potential to make a significant impact on the 25,000-acre net acreage position that we've put together.

Fourth, we are going to continue to improve the efficiency of our business. In every aspect, we will continue to look at costs, cycle times, and relative returns. In our view service costs have not come down to the level where they need to be for industry to be sustainable in this pricing environment. We are actively monitoring service costs and continuing to competitively bid all services. We have lease operating expense studies underway in virtually all of our areas. We are reassessing and in may cases deferring discretionary back-office projects, all this has worked that always has to be a priority, but the current downturn has certainly raised a level of urgency around it.

Fifth, we will position ourselves for an inevitable recovery. Clearly, this industry downturn has been more pernicious than others. We've seen in the past, then others that we've seen in the past couple of decades, primarily because of the global financial collapse. The commodity supply demand fundamentals are working, we have oversupply, waning demand, which adds up to much lower prices than the industry can sustained. It's painful at the moment, and we take the situation very seriously, we're being vigilant in tracking and monitoring the pieces of business that we control.

However, we also believe Rosetta is in a good position to weather the cycle and our goal is to emerge well positioned to continue building the company. We're going to guard our financial capacity jealously, but adjust our capital as appropriate. We're going to continue to consider attractive acquisitions like the constellation acquisitions we made at year-end. We're going to improve our cost structure, and build inventory, and we're going to continue filling our rigs schedule and permitting wells, so we can hit the ground running when the time is right.

So to summarize those five points again, we're going to continue to act rationally, live within our means, and preserve our liquidity, keep generating inventory, focus on getting more efficient and position ourselves for the recovery. We are a different company than we were just a year ago. The current environment is challenging, but I believe we have some unique attributes that should differentiate us in these times. Our core producing assets are largely held and much of our production is located in premium markets. We have significantly increased our project inventory with numerous concepts still to test our study. We have a very prudent operating plan in place for the year, but our plan also gives us the flexibility to respond to both organic and inorganic opportunities.

We have a team that's committed to growing our company, and after all that we've accomplished in 2008 it would be easy to get discouraged with the reversals of the marketplace. However, we believe we've got an opportunity now to advance our strategy and we are confident about the path that we are pursuing. So, we look forward to updating you on our progress throughout 2009. And with that I’m going to turn the call back to the moderator. And we will now take your questions.

Question-and-Answer Session

Operator

Thank you, sir. (Operator Instructions). And our first question today comes from Mark Lear, Sidoti & Company.

Mark Lear – Sidoti & Company

Good morning guys.

Randy L. Limbacher

Good morning, Mark.

Mark Lear – Sidoti & Company

Just talking about these, the increase in the inventory I was wondering how much of that is attributable to your core or your legacy assets and then I was wondering if you kind of break that down into how much inventory each location?

Randy L. Limbacher

Yeah Mark, Jim is kind of flipping through his statistics here, let me get Jim Craddock to address that.

Mark Lear – Sidoti & Company

Thanks.

James E. Craddock

Okay, Mark. Yeah, high percentage of it is in our core asset just kind of running through the roughly 300 Bcfe of risk inventory, about 3 of its in California, and 86 is in the DJ, did San Juan Basin, so I guess we round it to about 90 for that area, 48 in the Lobo, Perdido is about 20, 60 in the Green River basin and then the rest is spread across the number of the other assets including the South Texas position we just purchased and Onshore Others. So, that's as you can see a large percentage of it is before earnings will be operating.

Mark Lear – Sidoti & Company

Gotcha. And then I guess kind of looking at….

Randy L. Limbacher

May we let, am I let John tell you a little bit about what’s not in there as well as kind of a follow on to that John you want to.

John D. Clayton

Yeah Mark. I want to make sure that everybody understands when we talk about inventory. Those are the numbers that Jim reported in our core area on things there proven undeveloped probable is possible, but in order to have an appreciation for those numbers it's important to talk about plays we're pursuing that are not in that inventory. I’ll walk you through some of our large ones so when we talk about inventory it's not things like our Alberta Bakken position. I think Randy mentioned we picked up 230,000 acres up there. We know there is flowable oil in the system. We planned to drill our first two wells this year, huge position we don’t believe it's at the point yet to where we could start calling it inventory for you guys. Our Eagle Ford Shale position, we’ve got one well down that’s operated. We are encouraged by what we have seen to-date. We have 25,000 net acres in that play that’s also not in those inventory that Jim reported. Pinedale down spacing, I know a lot of operators are going down to five acre spacing, those numbers are not in there, but we are doing some more ones, looking at the grainage across our position as well as what is in there in DJ is the 500 locations that we’ve done the technical work on it feel comfortable we can put a rig out there tomorrow, but if you just simply do the math, on 40 acre development not including what we are calling inventory we’ve got an additional 1500 acres to 2,000 locations as well as if our pilot program that we did in ’08 is successful we even have further 20 acre down spacing. So, anyway my point is that when Jim closed on inventory numbers those are we would like to call them scrubbed inventory numbers, but I don't want to misrepresent that we don't have some what we have look at is some pretty exciting projects going on that were kind of little bit beyond inventory right now.

Randy L. Limbacher

Yeah. Mark I didn’t want to hijack your next question, but I mean that's the unrisk potential that's about 1.3 tees that hopefully you will see that growth in the future, but I will turn it back to you for your next question.

Mark Lear – Sidoti & Company

Well that was going to be the next one. So, I carefully appreciate the color there. But I guess, just to kind of get a little more flavor of all the new projects, you guys are adding, where you do think that the most upside might exist for you?

Randy L. Limbacher

There is probably a couple of ways to answer it. I would say the lowest risk upside potential that is not in those inventory numbers is probably the tight sands in California, and I think, as would be one and it also very low risk, I think around adding additional DJ Basin locations. So, I think those are things that have a reasonable probability of coming to bear, and but I think the Eagle Ford shale and the Bakken are higher risk, but are things that could materially impact the size of the company.

Mark Lear – Sidoti & Company

And then just looking at this Bakken is there a history of production from the Bakken up there, and if you guys do hit some good things there, is there a way to get the oil out of there currently?

James E. Craddock

I will address your second question first. The answer is yes it will take a little bit of work and some changes to infrastructure. Our acreage position is located directly west offsetting Cut Bank Field. So, it’s not like we're away from oil and gas production those that you guys are familiar with the Cut Bank field in the Alberta Basin it's been a pretty significant hydrocarbon producing basin in over many, many decades. Your first question, if you go back and look in the 1950s, which is where we've been studying some of the deep wells there was 24 deep wells that were penetrated in the basin, and some of those wells actually performed drill stem test on the Bakken. Now these are vertical wells test at the Bakken. What we were surprised to find out is that there is significant oil that was actually flowed to surface on more than some of these well. So, we've got multiple data points over a large acreage position that not only tells us that there is hydrocarbons in the system, but the reservoir Rockies is actually indicative of something that can flow hydrocarbons to surface. So, we're able to prove up commerciality through vertical and horizontal drilling and we are pretty excited about the upside.

Mark Lear – Sidoti & Company

Gotcha. Thanks a lot guys.

Operator

And we'll now go to Richard Rossi of Wunderlich Securities.

Richard Rossi – Wunderlich Securities

Good morning everybody.

Randy L. Limbacher

Good morning.

Richard Rossi – Wunderlich Securities

Couple of things, you were talking about, if you see service cost come down to real economic levels, you might consider doing more drilling, could you give us an idea of how far they've come down so far or what you've seen so far in the market, how much further would we have to go before you might want to change that?

Randy L. Limbacher

Jim.

James E. Craddock

Sure Richard. This is Jim Craddock. Yeah, we've seen I think some movement, but frankly not enough yet I guess one example is in South Texas where we are quite actively seeing rig rates drop a bit, but they were nowhere close to the levels that we see that we need to sustain this activity. We’ve seen stimulation cost come down, our most recent bid round I think we saw obvious kind of get ranges, but kind of 5% to 15% reduction that doesn’t feel like it’s very consistent with what we are seeing on commodity price drops. We’ve seen chemical cost come down [seeming] so forth, but in general it’s more in the kind of 5% to 20% range, and obviously, the industry has seen revenues drop much more significantly than that. So, we are kind of watching it, we stay kind of month-to-month various vendors and talk with them, we've bid out a large number of services. We are just going to keep watching it.

Richard Rossi – Wunderlich Securities

Would you say that we're maybe half way there?

James E. Craddock

Until half way yet, but it obviously every bid helps and so we'll keep kind of plug in away.

Randy L. Limbacher

Yeah Richard. I think it’s a combination of service costs and gas prices, but I think about it in terms of what kind of it, 2004 gas prices and still probably it not too far off of 2008 service costs. And so the math just doesn’t work I think that we’ve to got to see another 20% to 30% from where are right now or a significant ramp back up in gas price. So, it’s combination of one or the other.

Richard Rossi – Wunderlich Securities

Okay. And then the other thing, looking at the potential for acquisitions in a market that undoubtedly has seen a lot more properties come on the market recently. And I know this you are not going to be able to answer this with any dollar amount, but a sense of, would you go for a large acquisition, would you go and lever yourself up, take down all of your borrowing capacity, et cetera, obviously if it's attractive enough, you're certainly going to say yes, but what's your temperature on that right now?

Randy L. Limbacher

Well I’d say we really have a stronger preference for the smaller bolt-on type acquisitions the other thing I’d mention is for example the constellation deal and some of the things we are starting to see now it looked like they traded about PDP value, which is a situation that we haven’t seen since the mid-80s to early 90s and so evaluations are certainly attractive, but we have the liquidity to do a larger transaction, but I’d say we have a stronger preference for smaller bolt-on deals as opposed to a larger transaction using the cash.

Richard Rossi – Wunderlich Securities

Okay, well. Thank you very much. I will get back in the queue.

Randy L. Limbacher

Thank you.

Operator

(Operator Instructions). We will take our next question from [Phil Pace] of [Chambers Energy].

Phil Pace – Chambers Energy

Hello, Randy how are you?

Randy L. Limbacher

Phil, how are you doing?

Phil Pace – Chambers Energy

I couldn't be better. Thank you.

Randy L. Limbacher

Good.

Phil Pace – Chambers Energy

I don’t know the Sac Basin as well as I’d like could you give me a little bit of a color if you were going to drill there I think you were 13 for 14 last year what ignoring the recompletions, which sounds like where the better money returned are going to be what does the well look like in terms of EUR and what is the cost?

Randy L. Limbacher

Yeah, John you want to take Phil through selling. And there is several different play types out there and it's a pretty diversed basin I guess I’d just set it up by saying what we historically done was more conventional in nature and going forward is kind of putting that unconventional lens on it and so if we there is a lot of recompletion work right now, but we are seeing tight sands that are prevalent across the field and the idea is if you can make that work and marry that up in a couple of different areas you might have a pretty substantial drill bit program out there, but we've, while, I would let John kind of take you through some of the nuts and bolts there.

John D. Clayton

Good morning, Phil. I will try to maybe reference it to something I know you're familiar with. If you look at California, there is 16 productive horizons in our Rio Vista Gas Unit, which we operate and control at roughly 100% working interest. Depths range from 2,500 feet down to about 12,513 feet. So, when you hear a deep well in the Sacramento Basin, it's typically something that’s between 10,000 and 13,000 feet. If you look overtime there has been about 3.5 trillion cubic feet that’s been produced from the Basin. And I am going to exclude two reservoirs, one called the Emigh, spelled with an E and the other one called the Hamilton, because those are very similar to Gulf Coast type rocks, Darcie type rocks. Everything else, the way we are approaching this, the other 14 productive horizons they have hydrocarbons in them are sand shale sequences that I would like to say is very similar to the San Juan Basin, proper spacing is unknown, because drainage patterns are unknown, yet the resource accumulation appears to be there. The tight Capay was actually the first reservoir that we tackled if you looked at a resistivity log, you could barely tell that the sand was resistive, but going back in time, we knew that there was hydrocarbons in that sand just what mud locks shows and so forth. And going back in and fracture stimulating that one zone, Randy gave you the results we’ve done, six of those to-date I think the average production is about 650 Mcf a day per well. So,…

Phil Pace – Chambers Energy

What reserve would you put on that by the way?

John D. Clayton

Those will be a little tough, right now anything outside of the six wells we've done, we don’t even call inventory in Craddock's number, but we've quantified the resource in the Middle Capay alone, and we've got a 100 Bcf net over 30,000 acres to the company, its costing us right now roughly $500,000 or $600,000 for the program, and although the rates are high these are about four to eight weeks old, but if you put anywhere from 300 million to 400 million cubic feet gross per well you can see we've got a pretty attractive cost.

Phil Pace – Chambers Energy

Yeah.

John D. Clayton

We've got a couple of 100 wells in the field that all this is behind tight that we are going through and obviously you can't get all of them because some of them are producing in the lower zones, but from an analogous standpoint it's not well that we spent a lot of money on that we are going to come on at $10 million a day these are blocking and tackling type properties that really made some of the stuff we are familiar with in San Juan very commercial. So, we are excited about it, we've got, we are continuing with the Capay program and we will be testing another resource play in the field here that we hopefully will report on to you guys in a few more months, but drilling cost, I think you asked had at the down of my [notes] here, an expensive well to drill out there is probably about $1.5 million and then typical reserves are somewhere close to maybe three quarters or a Bcf per well. So,….

Phil Pace – Chambers Energy

That's very helpful. Thanks John.

John Clayton

You bet. Thanks.

Randy L. Limbacher

Thanks Phil.

Operator

And gentlemen at this time there are no additional questions in the queue. I'd like to turn it back to you for any additional or closing remarks.

Randy L. Limbacher

I don't have any additional remarks, but I appreciate you interest and Mike, myself, and others will be around today and be glad to take your calls and answer any other questions, if you think about it going forward, and we will look forward to updating you on our progress during the rest of the year. Again thanks a lot.

Operator

Ladies and gentlemen again that does conclude today’s conference. We thank you for your participation. You may now disconnect.

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Source: Rosetta Resources Inc. Q4 2008 Earnings Call Transcript
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