Laredo Petroleum Inc LPI
Q4 2012 Earnings Call Transcript
Transcript Call Date 03/12/2013

Operator: Good day, ladies and gentlemen, and welcome to the Laredo Petroleum Holdings, Inc. Fourth Quarter and Full Year 2012 Earnings Conference Call. My name is Sue and I'll be your operator for today. At this time, all participants are in a listen-only mode. We will be conducting a question-and-answer session after the financial and operations report. As a reminder, this conference is being recorded for replay purposes.

It is now my pleasure to introduce Mr. Rick Buterbaugh, Executive Vice President and Chief Financial Officer. You may proceed, sir.

Richard C. Buterbaugh - EVP and CFO: Thank you, Sue, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Jerry Schuyler, President and Chief Operating Officer; Pat Curth, Senior Vice President for Exploration and Land; John Minton, Senior Vice President of Reservoir Engineering; and Dan Schooley, Vice President of Marketing as well as additional members of our management team.

Before we begin this morning, let me remind you that during today's call we will be making forward-looking statements. These statements including those describing our beliefs, goals, expectations, forecasts, and assumptions are intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. The Company's actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. Additional information concerning certain risks and uncertainties relating to our business, prospects and results are available in the Company's filings with the SEC.

In addition, we will be making reference to adjusted net income and adjusted EBITDA which are non-GAAP financial measures. Reconciliations of GAAP net income to these non-GAAP financial measures are included in today's news release.

Also, as a reminder, Laredo reports operating and financial results including reserves and production on a two-stream basis, which accurately portrays our ownership in the oil and natural gas produced. Therefore the value of the natural gas liquids is included in the natural gas stream and pricing, not as part of our oil and condensate or included in a combined liquids total. If reported on a three-stream basis, Laredo's barrel of equivalent volumes for reserves and production including initial production rates would increase by approximately 20% which you should keep in mind when comparing to other companies that report on a three-stream basis. Similarly, Laredo's unit cost metrics will appear higher when compared to companies that report on a three-stream basis. However, the true economic value is the same.

Earlier today, the Company issued a news release detailing the financial and operating results for the fourth quarter and full year of 2012. If you do not have a copy of this news release, you may access it on the Company's website at www.laredopetro.com.

I'll now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

Randy A. Foutch - Chairman and CEO: Thanks Rick, and good morning, everyone. I'm very proud of our team's accomplishments in 2012 which resulted in growth of both our reserves and production to record levels. We also made significant progress in quantifying the value opportunity from our Permian Basin acreage position. In our core Garden City area, which now encompasses nearly 146,000 net acres. Delineation drilling during 2012 has now confirmed the horizontal development capability from four stacked shale zone, and we have already de-risked and confirmed the equivalent of 360,000 net acres for horizontal development from these zones. We still have the equivalent of approximate 224,000 net acres to de-risk in the future.

We also made significant progress on optimizing the horizontal drilling and well completions in this area, as Jerry will discuss in a minute in more detail. Reduction in the fourth quarter of 2012 increased 8% sequentially from the third quarter and was up 27% from the same period in 2011. This increase got us to an average daily production rate of about 33,300 barrels of oil equivalent per day. This resulted in total production for the year of a record 11.3 million barrels of oil equivalent, up 31% from the prior year and slightly exceeding our annual expectations.

Our production growth was driven by our focused drilling activities in the oil-rich Permian Basin. As a result of this concerted effort, oil production now represents approximately 44% of total production which is about a 500 point basis increase from a year ago.

Laredo's total crude reserves at year-end 2012 increased 21% to a record 188.6 million barrels of oil equivalent. We have once again grown our reserves more than 20% while meaningfully enhancing the quality of our reserves. At year-end, we had increased the oil component of our reserves to 52%, and 43% of our total reserves are now classified as proved developed.

We are pleased with our reserve resulting from the concentrated delineation program which is our stated focus in 2012. Delineation activities inherently have relatively higher capital intensity that resulted in an all-in F&D costs of 20.97 barrels of oil equivalent. But keep in mind that we believe this delineation program also identified total net reserve potential of more than 1.6 billion barrels equivalent, more than eight times our existing booked reserves. As we move closer toward full scale development at this massive resource base, we expect to meaningfully improve our capital efficiencies.

During 2013, we expect to begin utilizing multi-well drilling pads to begin optimizing the vertical and horizontal spacing of laterals. This will maximize the efficient and economic recovery of hydrocarbons from the four stacked horizontal targets. We expect reduced capital costs from these multi-well pads as we gain efficiencies from items such as reduced rig moves, more efficient water handling, use of common production facilities and so on.

In summary, our deliberate science-based approach has served us well in 2012. We have delineated and better defined the opportunity we see within our Permian Basin asset and we are converting potential into reserves and production. We plan to retain this disciplined approach, both operationally and financially, as we move into the development of this exceptional asset to truly maximize its value for all of our shareholders.

Now, I'll turn the call over to Jerry Schuyler, President and Chief Operating Officer.

Jerry R. Schuyler - President and COO: Thanks Randy. Good morning, everyone. Operationally, we had a good fourth quarter. During the quarter, we completed an additional 10 horizontal wells in the Wolfcamp and Cline shales in the Permian-Garden City area. They were all long laterals which we've defined as typically around 7,000 to 7,500 feet and with around 25 to 28 frac stages in each well.

We started moving towards the longer laterals last year. On average, the longer laterals have been meeting or exceeding the anticipated improved well performance. In our earnings release, we listed the 30 day IPs for the top ten wells to-date and I will remind you those rates are all two-stream.

If you want to compare these wells drilled, two wells drilled by other operators that reported three-stream, then the barrel of oil equivalent rates would be even higher, they'd be about 20% higher like Rick had mentioned. As expected, the majority of these top ten wells have long laterals, nine out of ten of them to be exact.

We are also continuing to improve our pumping efficiencies and optimize our completion techniques, and not surprisingly four of these top ten wells have been completed since the first of this year which we believe demonstrates we are realizing these improvements.

Additionally, I would like to point out that the top ten list includes long lateral wells from all four of our shales on targets, the Upper, the Middle, the Lower and the Cline shale which we certainly believe, this illustrates the economic viability of each of these zones.

We are also seeing some reductions in our recent drilling and completion AFEs and we are under $8 million for our Upper and Middle Wolfcamp long lateral wells; and we are around $9 million for the Lower Wolfcamp and Cline long lateral wells as well.

These cost improvements are being driven primarily from reduced pumping prices, improved pumping efficiencies. We got shorter flow back times when we are bringing the wells on. We are also high grading our rig fleets and crudes on several of the services. We anticipate more improvements in these areas and also some other areas and we do expect the downward trend on our well cost to continue.

Plus the horizontal well economics are attractive. We are working hard to minimize the number of verticals required for full scale development. As a result of these efforts, we have dropped from six to five vertical drilling rigs at the end of February. Therefore, we now have a total of eight rigs in the Permian including the three horizontal rigs.

Overall, we are very excited about what we're seeing in our Permian-Garden City area as we continue to grow the production and reserves with good economic returns. In the Granite Wash, in the Texas Panhandle and Western Oklahoma, we're continuing our three-rig horizontal rig program and completed an additional four horizontal wells in Q4. These wells are continuing to meet our performance expectations and as we previously announced, we have retained the bank and we are exploring strategic alternatives with these assets.

We also have a couple of exploration operation activities ongoing. We are in the process of completing our first horizontal Cline well in our Permian-China Grove acreage in Mitchell County. We also have a horizontal well producing hydrocarbons in Dalhart Basin where we plan to drilling an additional well later this year to do some further testing. We are early in the process in both of these area and we don't have any detailed information to report today.

With that, I'll turn it over to Rick.

Richard C. Buterbaugh - EVP and CFO: Thanks Jerry. As stated in our morning's news release, Laredo reported net income of $11.8 million or $0.09 per diluted share for the fourth quarter of 2012. This includes a non-cash pre-tax unrealized loss on derivatives of approximately $2.3 million. Excluding this unrealized loss, our adjusted net income for the quarter was $13.5 million, or $0.11 per diluted share, generally in line with analysts' average expectations.

For the full year, adjusted net income was $72.4 million or $0.57 per diluted share. The tables included in the news release and our annual report on Form 10-K that was filed this morning with the Securities and Exchange Commission detail our financial results for 2012 and the Company's first full year as a publicly traded Company. However, there are a few items that I would like to bring to your attention. Total oil and natural gas sales for 2012 increased nearly 15% from the prior year to approximately $584 million. This increase reflects a 42% increase in our oil production and a 23% increase in our natural gas production, which more than offset lower realized prices for both oil and natural gas which declined approximately 5% and 32% respectively from the 2011 levels.

Keep in mind that although we maintain an active commodity hedging program, Laredo does not use hedge accounting. Therefore, the impact of our oil and natural gas derivatives is not included within our reported oil and natural gas sales, but rather included below operating income as realized and unrealized gain or loss.

For 2012, the cash impact or realized portion of our commodity derivative program increased cash flows from operations by approximately $27 million. For the fourth quarter of 2012, unit cash operating expense including lease operating expenses, production taxes and the cash portion of G&A decreased approximately 10% year-over-year to $14.02 per barrel of equivalent and these costs decreased about 1% sequentially from the third quarter of 2012. For the year, unit cash operating costs remained essentially unchanged at $13.90 per barrel of equivalent.

As I mentioned in my opening remarks, please keep in mind that these metrics all reflect two-stream reporting.

Lower unit G&A expense and production taxes for the year more than offset higher unit lease operating expenses. The increase in unit lease operating expense reflects a combination of our focus on the development and increased production of oil volumes, which generally have a higher production cost, but also a much higher value than natural gas.

During the fourth quarter, we experienced increased workover expenses as we began implementing some proactive well maintenance efforts that we believe will provide longer-term well tubing integrity and minimize future workover expenses, as well as enhance the overall well performance.

Total unit operating expense including non-cash G&A and DD&A expense declined to $36.88 per barrel equivalent in the fourth quarter, down 8% from the prior year and down 2% sequentially from third quarter. For the year, total unit operating expense was $36.35 per barrel equivalent, reflecting higher depletion and stock-based compensation expense.

Interest expense for the fourth quarter and full year increased from the 2011 expense due to the issuance of $200 million of 9.5% senior unsecured notes in October of 2011 and $500 million of 7.375% senior unsecured notes in April of 2012. Laredo invested total cash capital of $920 million as budgeted for 2012 which includes $20.5 million relating to the acquisition the Permian Basin oil and gas properties.

Exploration and development expenditures excluding acquisitions totaled approximately $875 million of which about 89% was directed to the oil-rich Permian Basin. Adjusted EBITDA increased 17% in 2012 to approximately $452 million.

For 2013, our Board has approved the capital budget of $725 million, out of 20% reduction from the 2012 budget. Although near-term, we anticipate outspent cash flow from operations, we expect to do so at reducing levels.

We believe our existing credit facility provides us adequate liquidity for several years to continue to grow reserves and production through the systematic delineation and initial ramp up of development of Permian-Garden City asset.

As of today, our total liquidity stands at approximately $550 million. As we have expressed in the past, we are committed to maintaining a strong financial position and continually evaluate multiple funding options, including the divestiture of non-core assets, joint ventures, equity offerings or additional borrowings to fund the acceleration of development of the Permian asset at the appropriate time.

However, we will only exercise these funding mechanisms, if we truly believe it will positively impact the long-term value of our – for our existing shareholders. In December, Laredo issued operational and financial guidance for 2013. Incorporated in that guidance is the expectation of increasing production volumes throughout the year, as well as the positive impact on unit cost.

We are not changing our overall guidance for the year of 2013, which incorporates expectations for the first quarter of 2013 as follows. We anticipate total production volumes in the first quarter in the (range of) 2.9 million to 3.3 million barrels of oil equivalent.

Unit lease operating expense is expected in the range of $6 per barrel equivalent to $6.25. Production taxes are estimated at 7.5% of total oil and gas revenues. G&A expense, including both cash and non-cash portions, are estimated in the range of $6 to $6.50 per barrel equivalent and DD&A expense is estimated in the range $22.50 per barrel to $23 per barrel equivalent.

As you are all aware, the Midland-Cushing basis differential widened during the fourth quarter of 2012 and in early 2013. We have put in place additional sales contracts and basis hedges to help continue to mitigate this risk going forward. We have layered on Midland-Cushing basis hedges and sales contracts at an average basis differential of $1.74 per barrel on 10,000 barrels of oil per day beginning in February 2013 and ending in January of 2014. As a result, our unhedged price realizations for crude oil in the first quarter 2013 are expected to be in the range 85% to 90% of the NYMEX price.

Additionally, we have entered into pipeline commitments to initially transport 10,000 barrels of oil per day on the Longhorn pipeline to the Gulf Coast, and those volumes increased to approximately 23,000 barrels per day over a five-year period. This also helps mitigate our risk associated with the volatility in the Midland-Cushing basis differential. As a result of the basis hedges and pipeline commitments out of the Permian we believe that Laredo will still be able to deliver oil price realizations within our full year 2013 guidance in the range of 90% to 95% NYMEX.

Natural gas realizations for the first quarter of 2013 are expected in the range of 135% to 140% of NYMEX which takes into account the value of our liquids-rich natural gas. Randy?

Randy A. Foutch - Chairman and CEO: Thanks Rick. In summary, we took a very disciplined and deliberate approach to delivering quality results while delineating a significant portion of our acreage position and we did this by drilling and completing additional wells in all four stacked pay zones in 2012.

As a result of this, we have now de-risked a substantial portion of our Permian-Garden City acreage for the Upper Wolfcamp, Middle Wolfcamp, Lower Wolfcamp and Cline development; and we have a clear path for continued repeatable growth in reserves and production. In 2013, we will continue our efforts to de-risk the additional acreage in these zones, though 2013 will be focused on developing programs to ultimately assist in determining the optimal approach for us to minimize the efficient recovery of the vast resource potential that exists across our now de-risked acreage.

Sue, at this time, would you please open the line for any questions?

Transcript Call Date 03/12/2013

Operator: Will Green, Stephens.

Will Green - Stephens: I appreciate all the color with the rig count and everything. Do you guys have a number of horizontal wells you guys are targeting for '13 and if so what's the breakdown of each zone if you have that kind of color?

Randy A. Foutch - Chairman and CEO: We haven't exactly forecast well per zone or drilling per zone going forward. We tend to look at the results. We think that a substantive part of our drilling will be in the Upper, but we also now are seeing very, very, very good results in the Middle and Lower. So, I think we – as the year go through, we'll modify what zone we drill, but I think our bias is to drilling more horizontal as possible, and I think we will start the optimization and development process by drilling some pilots both stacked vertically and spaced horizontally which will involve more than just the Upper. The Cline we're in reasonably good shape in as far as knowing what we need to do on the development side. We do need to de-risk additional average over the year as we get the opportunity.

Will Green - Stephens: How should we think about one horizontal rig this year, how should we think about how quickly that can get a well drilled and online?

Jerry R. Schuyler - President and COO: The spuds are ranged from the 35, 40 days.

Will Green - Stephens: Then you guys jumping over to the vertical program, you guys have mentioned that you have seen some cost saves on the horizontals. How should we think about the verticals, I mean, I assume there is still some things you guys could do to reduce the cost on the verticals a little bit?

Randy A. Foutch - Chairman and CEO: We are actually seeing some reduction and we anticipate more as overall service cost – but no service cost are decreasing sum out there. We think we are going to have a component of vertical drilling for some time to come. We think it adds to the overall quality of the horizontal placement. We think it helps us on (DDC). So, we expect cost to go down there, but we also expect us to have some component of vertical drilling for some time to come.

Will Green - Stephens: Then I wanted to ask on the vertical program currently, how deep are you guys typically going and what zones are present in kind of the Garden City area that seemed pretty comp like, pretty common targets across your acreage?

Randy A. Foutch - Chairman and CEO: Almost all of our vertical drilling is from the Sprayberry through all three Wolfcamp zones, the Upper, Middle and Lower into the Cline and also into the Strawn and Atoka. We do have great 3D seismic across this acreage. So, we occasionally see a reason to take a well to the Devonian (specimen), but almost a 100% of our drilling goes all the way through all of those zones.

Operator: Abhishek Sinha, Bank of America.

Abhishek Sinha - Bank of America: Just wanted to ask a couple of questions here. First, when do you expect to spend entire acreage, so you remaining 224,000 net acres would be this year or it could go to next year?

Randy A. Foutch - Chairman and CEO: I think the process of de-risking that acreage is probably going to take a couple of more years. We think that with the amount of acreage that we de-risk we're probably headed toward drilling a development program type well and activity within the de-risked acreage. We obviously want to get at the delineation program for the rest of that acreage as soon as we can. But the flipside of that is, we'd like to minimize one-off locations and try and head toward drilling locations where we maximize the rate of return and everything else by having common facilities, common pad and those things. So, there will be some delineation go-through for the next couple of years, but I think the majority of what we do is probably going to be in the development area.

Abhishek Sinha - Bank of America: Regarding your asset divestitures, so assuming that it goes according to the plan, how could that change your rig activity in the Permian going forward?

Randy A. Foutch - Chairman and CEO: I think we see a bias toward less vertical which we've talked about. We think we're going to have to run – I think we've said five or six vertical rigs for some time to come and it's actually several years out before we can reduce that. I think as we go forward with the bias toward the horizontal when we have opportunities will perhaps increasing that cadence. But our cadence today is more data constrained than any other thing. We would like to see a better well history, more production history, more pressure history before we changed or increased the cadence very much. Rick, do you want add something to that?

Abhishek Sinha - Bank of America: Last thing, I just noticed like in your Lower Wolfcamp results for the 30 day IP, that is significantly better than what we had last time. So is the longer lateral length, that's the only reason something else wasn't done to it, so what actually made the difference?

Jerry R. Schuyler - President and COO: No, it's only the second lower lateral that we had drilled. They are both 7,500 feet. So the laterals are the same and actually both of them are significantly better than what we had in our type curve that's out. So, we are optimistic, but it's just very early.

Randy A. Foutch - Chairman and CEO: Yeah, with only a couple of wells, it's hard for us to – while we obviously are very, very pleased with the results, a couple of wells doesn't make us want to change our overall modeling and assessment yet.

Abhishek Sinha - Bank of America: Then one last thing is like, can you make some comment on the oil gas ratio in the Lower Wolfcamp, is it a little bit lower than the general, Middle and Upper, how does that weigh?

Randy A. Foutch - Chairman and CEO: John, do you or Dan want to...?

John E. Minton - SVP, Reservoir Engineering: Yeah, I think we look at that 30-day rates and we look at those gas-oil ratios and our economic models will really run at slightly less of an oil percentage. So, this is a little better than what we had predicted to come in. But as Randy indicated and Jerry indicated, we only have a couple of wells and it's really early. So, we just need to follow the information and see where the production takes us.

Operator: Mario Barraza, Tuohy Brothers.

Mario Barraza - Tuohy Brothers: Just wanted to try and drill down a little more on your delineation drilling. You've only completed a few Middle and Lower horizontal Wolfcamp wells to-date. Can you really talk about your confidence in the play and how you came about reaching the 80,000 net acres for the Middle Wolfcamp and the 73,000 net for the Lower Wolfcamp de-risk to-date?

Randy A. Foutch - Chairman and CEO: I love that question. Thank you for asking it. Pat and I are fighting over who gets to answer that question. Pat, do you want to take it?

Patrick J. Curth - SVP, Exploration and Land: Let me start off and I'd like to remind everybody that we have a phenomenal database out there that consists of over 3,000 feet of whole cores, over 500 sidewall cores, numerous single zone competitions. And when you take that information, the petrophysical data tied into our drilling program to-date, we have a high degree of confidence that the acreage that we have said we de-risk has commercial potential. But we tied all into our complete database and we also have as we pointed out earlier, over 250 deep vertical wells that helps us give us (indiscernible).

Mario Barraza - Tuohy Brothers: Can you too de-risk you acreage and you build your inventory. I know you say, you have a data room open in the Granite wash, how do you feel about possibly opening a data room for your Permian acreage? Or would you rather tap to capital markets to accelerate development?

Richard C. Buterbaugh - EVP and CFO: Mario, we look – one of our goals is to maintain as much flexibility as possible. We look at any number of different financing methods, essentially the same way. As far as what is the impact that each transaction and equity raise, a debt offering would have on our existing shareholders. It comes down to what is the value that we could receive in transaction, what is the value of the joint venture and really what is going to be the most beneficial to our existing shareholders. At this time, we're focused on the Granite Wash as a potential divestment opportunity, but have not made any firm decisions that we will divest. It's the value of that relative to where those proceeds could be redeployed. At this time, we're not doing anything on our Garden City asset. We still think it's a little early on. We want to understand as much that asset basis we can. Before we determine rather or not, it makes sense to do any type of transaction on that asset. We do think there is a tremendous amount of running room remaining on that Garden City asset and that it may be a little premature or expensive to do any type of transaction with that at this time.

Operator: Gil Yang, Discern.

Gil Yang - Discern: Just to follow-up on one of the previous questions. You talked about the de-risking and sort of the criteria – or some of the information that you have to do that de-risking. Can you talk a little bit more about the specifics for each of the different zones maybe? What is it that limits the acreage to that perspective acreage? Is it the thickness, is it depth, is it oil in place fracability? Could you give us a little bit of color as to what limits it to sort of the 73,000 to 127,000 for each of the different zones?

Randy A. Foutch - Chairman and CEO: There are thoughts that you could perhaps argue that all of it's been de-risked. In our mind, we've tended to – we have a lot of data that suggests there is great continuity of thickness, great continuity of reservoir parameters geology. We know that as we go up and down that 80-mile train there will be some variability. There just has to be. But the criteria for us on the de-risking has lots of positive attributes in that we're not seeing a lot of changes. In fact, as Jerry mentioned, some of our results are better than we expected. For us, it's really continuity with our database and proven horizontal production. So based upon the 250 deep wells and the 700 plus shallow well, the database that Pat went into, we are developing a great deal of confidence in the potential. But for us to call it a de-risk we would like to see continuity of all that other data with proven horizontal production.

Gil Yang - Discern: So, is that suggesting that the – for example, with the 80,000 in the Middle Wolfcamp, is it just that you haven't tested the other 40,000 or 60,000 or so or is it that have you tested it and you found that the continuity isn't sufficient?

Randy A. Foutch - Chairman and CEO: No, it is that we have not yet tested it. We see – all the data we have makes us think that we need to test it; we need to get on with it. We see it as having very, very similar attributes. We just as yet, again, our criteria is that we actually need to produce in a horizontal well.

Gil Yang - Discern: So maybe to flip it around, if we were to sit here in two years and you've drilled all the wells you need to, is it possible that each of the different zones will have been de-risked for about 140,000 acres?

Randy A. Foutch - Chairman and CEO: I think that's a possibility.

Gil Yang - Discern: So in none of the data you've seen, have you been able to exclude any of the acreage where you've written off, so to speak, where you don't think it's prospective?

Randy A. Foutch - Chairman and CEO: We haven't yet tested the Northeast corner which I think is something like 20,000 acres or 25,000 acres and we do see a slight change in paces. It gets a couple of more percent carbonaceous. That's the only significant change we see in that entire acreage block and we don't know if that's negative or positive. We just haven't tested it yet. So our view today is that the potential exists for it all to be there. Obviously, over that 80-mile long train there's going to be some variation.

Gil Yang - Discern: Where do you think well costs will eventually end up given all the trends you're seeing?

Randy A. Foutch - Chairman and CEO: We haven't forecasted where they are going to wind up. What we do though, just to make sure, is we tend to use our modeling and report well costs on what we've done, what we've historically done over the last year or six months or so, and the point I want to make on that and thanks for the question is that, we use AFEs that are historical and it includes everything you need to produce the well including surface facilities, production tie-ins, tanks, everything. And on some of our AFEs that adds anywhere from $150,000, $200,000 to $500,000 on the AFE. Some people report that separately, but the takeaway you should have I think is that, it's very, very economic using those historical complete cost and this should be the highest cost we see, so things should get better as we move into the development program.

Operator: Jeff Hayden, KLR Group.

Jeff Hayden - KLR Group: Actually, just want to follow-up on Gil's question a little bit on the well cost. You know one, it seems like you guys have done a good job kind of pushing the cost down little bit, wonder if you could detail a little more for us as far as kind of what's changed to push those down a little further, and then as far as looking at well cost going forward, assuming we don't have any changes in overall service cost, what are some of the things you guys could do as you increase the efficiencies to try to drive additional cost out of it?

Richard C. Buterbaugh - EVP and CFO: We see that – and again, we tend to talk about what we've done, not trying to look at what we'd not do a couple of years from now. We do look at and compare our AFEs to everybody's out there, so we normalize those, we have a good handle on it. We've gotten more efficient on spud to spud on a well through a variety of things. I mean costs have going down on a number of our services, but we've also got more efficient in how we do it on simple of the things. So, it's not – there hasn't been a 10% magic bullet, it's been a series of 1% and 2% improvements across the Board. The things that change when we go to multi-pad development are the obvious things like – you don't have to tieback in long distances to surface facilities. You can use common surface facilities, same pad. You don't have to move – rig move is a pretty expensive thing, when you moving it miles and miles. We don't have to do that. We'll figure out how to handle frac water and frac sand without having to rebuild new pits and everything else on each slope. So, we are looking forward to seeing what the development program actually gives us in reduced cost. But again, I'll take the takeaway that we do compare ourselves to others. We – AFE ever cost including full surface facilities when we need it and we have a great rate of return as it is today and it's only going to get better, and it is – the thing that comforts us is that with the amount of acreage we de-risk and with the database we have on the rest of acreage, we think we've got great sustainability on yielding a good return for years to come, which should only get better.

Jerry R. Schuyler - President and COO: You asked the question about if service cost don't go down and we are doing a lot of things other than just getting good service cost. The efficiencies that I referenced were like we completed 35 horizontal wells last and there were only a couple of zones that we didn't get fraced away which is a reflection of utilizing crews and everybody knowing what they're doing. So, even if costs don't go down, by (high-grading) these contractors we will be reducing downtime. I mean, right now, we think there's a market – or we have significant gains that can be made by just improving downtimes and by (high-grading) a lot of these services, things like that should help us continue to push these costs down pretty significantly.

Jeff Hayden - KLR Group: Just one more from me. Looking at the well results you guys provided for us, it does look like the oil component is higher than what you guys are modeling. Just wondering if you could talk about the GOR trends for the wells that have been producing. Have they been kind of hanging in there, has the GOR has been going up? Any additional color you could give would be great.

Randy A. Foutch - Chairman and CEO: I'll take the first crack at that and then let John jump in if he wants to. When we did our modeling early on we built into the model over the life of the production, the 30, 40, 50 year life of the production a 5% or 7% kind of number, an increase in GOR over the life of that well. I think that's a number that we're 10 years away from knowing what it really is going to be. The GOR from north to south in our field, we have seen a little bit of variability. We don't have enough data. I mean, when you see it in one well 10 or 15 miles away from any other well, that is data but it may not be as completely meaningful as you would like. The modeling on the – losing some of it over 5% or 7% over the life of the well, that still remains to be seen, but the variability in GOR that we've seen has only been in the Cline. That's very positive in that the Wolfcamp so far with our existing wells which are limited in the Middle and the Lower; we are not seeing any variability in that GOR. Did that answer?

Jeff Hayden - KLR Group: Yeah, it did. I guess just kind of a follow-up to that, in the individual wells, I mean, have we been kind of hanging in there, kind of the same oil gas percentage that we've been seeing on these 30 day rates?

John E. Minton - SVP, Reservoir Engineering: Effectively yes. But keep in mind, we are looking at – when we do our reserves, when we do our production forecast, we project the oil curve separately from the gas curve and just in general, we are driven by the actual data to cause us to make those type of changes. But in essence, what's happening, it's a – the gas decline appears to be just slightly shallower than the oil decline. So, it looks like the slightly increasing GOR based upon the two or three years history that we have on the majority of our wells and we grow all that together and look at kind of the overall average in that regard.

Operator: David Tameron, Wells Fargo.

David Tameron - Wells Fargo: Can you guys talk a little bit, you mentioned the workover maintenance that you're doing in some of the wells and I guess that was Rick that referenced that and talked about some of the tubing. Can you just talk about exactly what you doing in the wells and what vintage age these wells that you are performing the workover maintenance on?

Jerry R. Schuyler - President and COO: David the – the larger number of wells out there came from our acquisition, so the workovers that we're doing are primarily in the out Southern acreage. It's what we've been doing that we believe are driving these costs. It should drive the cost down over the long haul is we aren't just going in and replacing and tying, there is no coated strings of tubing and pretty much all the rods were steel, so we've gone in and we've put fiberglass rods in some wells and when we pull the tubing in these wells, we actually inspect so that we don't run back the pipe that's just getting ready to fail and we are running coated back in, in the lower joints, but we're doing things that should bring down the failure rate and we're seeing results of that already, so we're pretty encouraged about what we're doing.

Randy A. Foutch - Chairman and CEO: And just keep in mind next month, a bad – we're not in bad position at all on that, we're just trying to make it better.

David Tameron - Wells Fargo: On the China Grove acreages, could you remind – when do you guys things and I think we talked about this last week Randy, but when do you guys think, you will have a good handle on what you have up there and then I think you are drilling a Cline well as a perspective for any of the other formations out there?

Randy A. Foutch - Chairman and CEO: That acreage is – we view it as principally a Cline play. There may be, you know, there's lots of talk about Mississippian, but we bought it trying to take what we knew in Garden City and leverage it up into another sub-basin. We bought that acreage very, very specifically, detailed by outline and our first well is horizontal well is being completed as we speak, early in the flow back, no meaningful data positive or negative there, I don't think. And I actually think David that we will get this well on look at a while probably drilling other well or so, I would think maybe this year. So, I think we're still several quarters away from talking about whether or not, we're happy or sad with what we have there.

Operator: Dan McSpirit, BMO Capital Markets.

Dan McSpirit - BMO Capital Markets: Do the rates from the wells that maybe top 10 list in today's press release support the upper range of the EURs, you outlined in your corporate presentation. Forgive me, if that question was already asked, I'm just asking for modeling purposes.

John E. Minton - SVP, Reservoir Engineering: Well, let me tackle that one. It's off to a good start. You got 30 days' worth of history, but certainly from a reserve – from my reserve perspective, I'm going to a lot more basins to see if that holds up there or what that decline truly does with time. I know if it sticks to a type curve and all you got to do is raise the type curve, it increases the EUR. But really it's too early to call that.

Randy A. Foutch - Chairman and CEO: Our view is that we like positive information and we need a lot more of it before we adjust. We're very happy with what we see, but we would like to see more.

Dan McSpirit - BMO Capital Markets: Then just a follow-up here, again just a modeling question here. What about the rates on the wells I guess that didn't make the top 10 list? Do they differ much from what was presented today? Again, just asking for modeling purposes here.

Randy A. Foutch - Chairman and CEO: Again, I think, we haven't seen enough data to change our model. We do have some spread on our results there. There is some well here and there that for one reason or another not as good. But I think we're pretty excited about where we stand compared to the model and I certainly think that as time goes forward, we'll adjust that model with cost and we'll adjust with EURs. But we're pretty happy with where the data are landing on our model today.

John E. Minton - SVP, Reservoir Engineering: I'd like to add to that just a little bit and from our perspective, we don't look at the top third of say the better wells. We try to take into account all the information, the good, the bad and the ugly to look at these things from that perspective and try to shoot the middle of the road as far as what we're putting together in our economic models and then we look back to continually see how that history is actually fitting that model and adjust as we get competence that it needs to be adjusted.

Operator: Daren Oddenino, C.K. Cooper.

Daren Oddenino - C.K. Cooper & Company: Going back to your Permian-China Grove acreage, you kind of talked about the increasing industry activity in the area. Can you touch on that a little bit and what you are seeing up there from other operators?

Randy A. Foutch - Chairman and CEO: We're actually kind of excited about that industry activity. As you know, we were the early entry into the Cline and Wolfcamp and we said this often when we started in Glasscock County, there was one another rig drilling; we brought in the second rig and doubled the rig count. Now there's, I don't know, 35, 40 something rigs drilling there. When we brought our China Grove acreage, we were out there early and there wasn't much activity around us at all. We think our acreage was bought very, very specifically. We're seeing that data from the other operators and we are pleased to have it and we are incorporating that into what we think about our acreage. I'm not sure that a lot of that acreage is directly comparable to ours at this point. So, the proof on our acreage is going to be have to our drilling.

Operator: Joe Allman, JPMorgan.

Joseph Allman - JPMorgan: The first question is on financing, so just – could you just give us your thoughts around your financial position and what kind of financing you might need to do this year. I know that you are in a process of thinking about selling the Granite Wash and maybe some other non-core acreage, but would you need in your view to get the balance sheet where you wanted to be, would you need to do something beyond that or do you think if you were successful selling that – those assets, would that take care of it for now, so just thoughts around that?

Richard C. Buterbaugh - EVP and CFO: Joe, we don't believe we have to do anything at this point and probably not anything for the next couple of years. Our current liquidity and the borrowing base that we have on our credit facility gives us adequate liquidity to maintain the existing type of capital program in the $725 million range that we're doing in 2013 probably for several years. Keeping in mind that as we spend that $725 million, we also anticipate that we will be growing production and therefore cash flow plus funding of greater and greater percentage of that capital spend. So, we don't feel that we're under any pressure that we have do anything. We certainly aren't capital constrained or believe that we are at this point. As far as our development program, we're more data constrained. We want to get some of the results of our pilot programs in place before we really start accelerating the development of that asset.

Joseph Allman - JPMorgan: So, Rick, even though you don't necessarily have to do anything, is the balance sheet where you want it to be or ideally would you like to see metrics like net debt, EBITDA be lower than where they are now and so, even though you don't have to, you would like to improve the balance sheet.

Richard C. Buterbaugh - EVP and CFO: I guess in this role, you'd always like to see debt metrics a little bit lower, but we're very comfortable with where we are today. Our net debt to EBITDA on a trailing 12-month basis is about 2.6 times. That may go up slightly during the course of this year, but probably come down overall. I'd say as it starts approaching or if it started to approach three times is when I would start getting a little less comfortable. But certainly today, we think it's very manageable. One of the things we obviously do is take a pretty aggressive approach to our hedging program, which is really in fairly good shape for 2013, and we are looking layering on additional hedges for years two, three and four as well. For 2013, we have a little over 60% of both are oil and gas volumes hedged at a reasonable prices, our average floor price on our hedges for oil are in the $84 range and for natural gas, the equivalent of roughly $4.25 per Mcf.

Randy A. Foutch - Chairman and CEO: Operator, I think we're running out of time. Rick, we have time for one more.

Richard C. Buterbaugh - EVP and CFO: Su?

Operator: Brian Gamble, Simmons & Company.

Brian Gamble - Simmons & Company: Just a couple of follow-ups, Randy, you mentioned multi-well pads in '13. Is that the plan for all the wells as you see it currently and maybe – I think you said, obviously the flexibility is the biggest issue that you're concerned about. If you do multi wells versus doing singles, could you just give us the cost delta between the two if that's the case?

Randy A. Foutch - Chairman and CEO: Yeah, we haven't worked out the cost delta. So, I can't give that to you. And I'm glad you asked the question, because I think unfortunately it's going to take us several years to move to more pad drilling with multi-wells off each pad. I think the way we view the de-risking process and the way we view the way to approach this, we're still going to be drilling a fair number of one-off wells through '13 and probably well into '14 and '15. We'll start the development program this year. We'll move toward it as quick as we can, but it's not going to be a light switch turn on or turn off where we in a period of a quarter to move to all pad drilling. It's going to take us I think several more years to really get to where the majority of it's pad drilling.

Brian Gamble - Simmons & Company: Then on the workover expenses, those are a part of Q4. Those are continuing in Q1 and as we go through 2013 and I'm assuming if they do, they are already a part of the cost guidance you gave earlier?

Richard C. Buterbaugh - EVP and CFO: Yes, those additional workover expenses are part of our 2013 guidance.

Brian Gamble - Simmons & Company: And they go through the entire year or you think that those conclude at some point during the year?

Richard C. Buterbaugh - EVP and CFO: I think our view is that what we are doing over time will get us in a position to where those wells don't need pulling in its own in that area. But I think also to be completely (brine) with the number of wells we are drilling, with 700 plus producing wells out there, I think over time, we're going to be working over as they age more and more wells.

Operator: Thank you.

Richard C. Buterbaugh - EVP and CFO: Thank you, Sue. At this time, I would like to thank everybody for their time this morning and their continued interest in Laredo. This concludes our call.

Operator: Thank you for joining today's conference. This concludes your presentation. You may now disconnect. Good day.