Richard C. Buterbaugh - Chief Financial Officer and Executive Vice President Randy A.

Foutch - Founder, Chairman and Chief Executive Officer Jerry R. Schuyler - President, Chief Operating Officer and Director John E.

Minton - Senior Vice President of Reservoir Engineering Patrick J. Curth - Senior Vice President of Exploration & Land Dan C.

Schooley - Vice President of Marketing

Will Green - Stephens Inc., Research Division Abhishek Sinha - BofA Merrill Lynch, Research Division Mario Barraza - Tuohy Brothers Investment Research, Inc. Gilbert K.

Yang - DISCERN Investment Analytics, Inc Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division David R.

Tameron - Wells Fargo Securities, LLC, Research Division Dan McSpirit - BMO Capital Markets U.S. Daren M.

Oddenino - C. K.

Cooper & Company, Inc., Research Division Joseph D. Allman - JP Morgan Chase & Co, Research Division Brian D.

Gamble - Simmons & Company International, Research Division

Thank you, Sue, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Jerry Schuyler, our 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 for 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 on 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 2-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 3-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 3-stream basis. Similarly, Laredo's unit cost metrics will appear higher when compared to companies that report on a 3-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.

Thanks, Rick, and good morning, everyone. I am very proud of our team's accomplishments in 2012, which resulted in growth of both our reserves and production to record levels.

And 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 4 stacked shale zones.

And we have already derisked and confirmed the equivalent of 360,000 net acres for horizontal development from these zones. We still have the equivalent of approximately 224,000 net acres to derisk 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 and in more detail. Production 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 guide 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 proved 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 reserves 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 FD&A cost 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 8x our existing booked reserves.

As we move closer toward full-scale development of 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 4 stacked horizontal targets. We expect to reduce capital costs from these multi-well pads as we gain efficiencies from items such as reduced rig moves, more efficient water handling, the 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.

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 10 wells to date and I'll remind you, those rates are all 2-stream.

If you want to compare these wells drilled -- 2 wells drilled by other operators that reported 3-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 10 wells have long laterals, 9 out of 10 of them to be exact. We are also continuing to improve our pumping efficiencies and optimize our completion techniques and not surprisingly, 4 of these top 10 wells have been completed since the first of this year, which we believe demonstrates we are realizing these improvements.

Additionally, I'd like to point out that the top 10 list includes the long lateral wells from all 4 of our shale zone 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're also seeing some reductions in our recent drilling and completion AFEs.

We are under $8 million for our Upper and Middle Wolfcamp long lateral wells and we're 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've got shorter flowback times when we're bringing the wells on. We're also high grading our rig fleets and crews 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. As the horizontal well economics are more 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 6 to 5 vertical drilling rigs at the end of February. Therefore, we now have a total of 8 rigs in the Permian, including the 3 horizontal rigs.

Overall, we are very excited about what we're seeing in our Permian-Garden City area as we've continued to grow the production and reserves with good economic returns. In the Granite Wash and the Texas Panhandle in Western Oklahoma, we are continuing our 3-rig horizontal rig program and completed an additional 4 horizontal wells in Q4.

These wells are continuing to meet our performance expectations. And as we've 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 -- Permian-China Grove acreage in Mitchell County.

We also have a horizontal well producing hydrocarbons in the Dalhart Basin where we plan to drill an additional well later this year to do some further testing. We are early in the process in both of these areas and we don't have any detailed information to report today.

And with that, I'll turn it over to Rick.

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 noncash, pretax, 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 analyst 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 cost 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 2-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 expense as we began implementing some proactive well maintenance efforts that we believe will provide longer-term well tubing integrity and minimize future workover expense, as well as enhance the overall well performance.

Total unit operating expense, including noncash G&A and DD&A expense, declined to $36.88 per barrel of equivalent in the fourth quarter, down 8% from the prior year and down 2% sequentially from the 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 of 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.

In 2013, our board has approved the capital budget of $725 million, about a 20% reduction from the 2012 budget. Although near term, we anticipate to outspend 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 our Permian-Garden City asset. As of today, the 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 noncore assets, joint ventures, equity offerings or additional borrowings to fund the acceleration of development of our 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 financial guidance for 2013. Incorporated in that guidance is the expectation of increasing production volumes throughout the year, as well as their 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 of 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 of equivalent and DD&A expense is estimated in the range of $22.50 per barrel to $23 per barrel of 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 of 2013 are expected to be in the range of 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 increased -- and those volumes increased to approximately 23,000 per barrels per day over a 5-year period.

This also helps mitigate our risk of -- 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?

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 4 stacked pay zones in 2012. As a result of this, we have now derisked a substantial portion of our Permian-Garden City acreage for the Upper Wolfcamp, the 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 derisk the additional acreage in these zones. So 2013 will be focused on developing programs to ultimately assist in determining the optimal approach for us to maximize the efficient recovery of the vast resource potential that exists across our now derisked acreage.

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

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?

We haven't exactly forecast wells 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 goes through, we'll modify what zones we drill.

But I think our bias is to drilling more horizontal, if possible. And I think we'll 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 derisk additional acreage over the year as we get the opportunity.

Okay. I appreciate that.

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?

Yes. Our spud-to-spuds are -- range from the 35, 40 days.

Great. And then you guys -- jumping over to the vertical program, you guys have mentioned that you've seen some cost saves on the horizontals.

How should we think about verticals? I mean, I assume there's still some things you guys could do to reduce the cost on the verticals a little bit?

Yes. And we're actually seeing some reduction that we anticipate more as overall service cost -- everybody knows service costs are decreasing some out there.

We think we're 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 the DDC. So we expect cost to go down there, but we also expect just to have some component of vertical drilling for some time to come.

Sure. And 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 -- like pretty common targets across your acreage?

Almost all of our vertical drilling is from the Spraberry through all 3 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 block, so we occasionally see a reason to take a well to the Devonian Fusselman.

But most -- almost 100% of our drilling goes all the way through all of those zones.

I just wanted to ask a couple of questions here. First, when do you expect to derisk the entire acreage to your remaining 224,000 total net acres?

Will it be this year or it could go to next year?

I think the process of derisking that acreage is probably going to take a couple more years. We think that with the amount of acreage that we've derisked, we're probably headed toward drilling a development program type well and activity within the derisked acreage.

We obviously want to get at the delineation program for the rest of that acreage as soon as we can. But we -- the flip side 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'll be some delineation go-through for the next couple of years, but I think the majority what we do is probably going to be in the development area.

Sure. And regarding your asset that was insured, so assuming that goes according to the plan, how could that change your rig activity in the Permian going forward?

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 5 or 6 vertical rigs for some time to come and it's actually several years out before we can reduce that.

And I think as we go forward with the bias toward the horizontal, when we have opportunities, we'll perhaps increase that cadence. But our cadence today is more data constraint than any other thing.

We would like to see a better well history, more production history, more pressure history before we change or increase the cadence very much. Rick, do you want to add something to that?

Sure. And last thing, I just noticed like on your Lower Wolfcamp reserves of 130 [ph] to IP, that is significantly better than what we had last time.

So is the lower lateral land, that's the only reason from the Edmonton [ph] to it? so what actually made the difference?

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're optimistic, but it's just very early.

Yes, 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.

Sure. And then one last thing I'd like -- can you make some color on the oil-gas ratio and the Lower Wolfcamp?

Is it a little bit lower than the general middle and upper? How does that vary?

John, the year or day and [indiscernible]?

Yes, I think we look at that 30-day rates and we look at those DSO 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, 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.

I'm 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 derisked to date?

I love that question. Thank you for asking it.

Pat and I fight over who gets to answer that question. Pat, do you want to take it?

Let me start off, and I'd like to remind everybody that we have a phenomenal database out here that consists of over 3,000 feet of whole cores, over 500 side wall cores, numerous single zone completions. And when you take that information, the petrophysical data, and tie it into our drilling program to date, we have a high degree of confidence that the acreage that we have said we've de-risked has commercial potential.

But it's -- we tie it all in to our complete database. And we also have, as has been pointed out earlier, some over 250 of deep vertical wells that helps us, give us a lot of [indiscernible] .

And as you continue to de-risk your acreage and you build out your inventory, I know you say have 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 the capital markets to accelerate development?

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 a transaction, an equity raise, a debt offering, would have on our existing shareholders. It comes down to what is the value that we could receive in a transaction, what is the value of a 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. 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 of that asset base we can before we determine whether or not it makes sense to do any type of transaction on that asset. We do think there's 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.

Just a follow-up on one of the previous questions. You talked about the derisking and sort of the -- or the -- some of the information that you have to do that derisking.

Can you talk a little bit more about the specifics for the -- 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, frac ability? Could you give us a little bit of color as of what limits it to, sort of the 73,000 to 127,000 for each of the different zones?

Gil, thanks for the question. We've -- 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's great continuity of thickness, great continuity of reservoir parameters, geology. We know that as we go up and down that 80-mile trend, there'll be some variability, there just has to be.

But the criteria for us on derisking has lots of positive attributes and 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 150 deep wells, and the 700 plus shallow wells, that the database that Pat went into, we're developing a great deal of confidence in the potential.

But for us to call it de-risked, we'd like to see continuity of all that other data with proven horizontal production.

So does that -- thanks for that answer, Randy. Does that suggest then 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 you tested it, and you found that the continuity isn't sufficient?

No, we've -- it is that we have not yet tested it. We see all the data we have.

It 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 it in a horizontal well.

Okay, and so, maybe to flip it around, you prefer to sit here in 2 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?

I think that's a possibility.

And none of the data you've seen, have you been able to exclude any of the acreage? Or you've written it off, so to speak, whereas that you don't think it's perspective?

We haven't yet tested the Northeast corner, which I think's something like 20,000 or 25,000 acres, and we do see a slight change in paces. It gets a couple 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 trend, there's going to be some variation.

And where do you think well costs will eventually end up, given all the trend you're seeing?

We haven't forecasted where they're going to wind up, what we do see though, just to make sure, is we tend to use our modeling and report well cost on what we've done, what we've historically done over the last year or 6 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.

Actually, just want to follow up on Gil's question a little bit on the well costs. One, it seems like you guys have done a good job, kind of pushing the costs down a little bit.

Wondered 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 costs going forward, assuming we don't have any changes in overall service costs, what are some of the things you guys could do as you increase the efficiencies to try to drive additional cost out of it?

We see that, and again, we tend to talk about what we've done, not try and look at what we might 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.

Our -- we've gotten more efficient on spud to, to spud on a well, through a variety of things. And I mean, costs have gone down on a number of our services, but we've also gotten more efficient in how we do it on simpler things.

So it's not a -- 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 tie back in long distances to surface facilities. You can use common surface facilities.

Same pad, you don't have to mob. A rig mob is a pretty expensive thing when you're moving at miles and miles.

We don't have to do that. We will be able -- 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're 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, every 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.

You asked the question about if the service costs don't go down. And we are doing a lot of things other than just getting good service cost.

The efficiencies that I referenced where, like, we played at 35 horizontal wells last year, and there was only a couple of zones that we didn't get frac-ed 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.

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 significant.

Okay, I really appreciate that, the additional color, guys. Just one more for 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?

As far as the wells have been producing? Have they been kind of hanging in there?

Has the GOR been going up? Any additional color you could give would be great.

I'll take a 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 models over the life of the production, the 30, 40, 50-year life of the production, a 5% or 7% kind of number, that increase in GOR over the life of that well.

And 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 1 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 it, losing some of it over a 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, and that's very positive, in that the Wolfcamp, so far, with our existing wells, which are limited in the middle and the lower, we're not seeing any variability in that GOR.

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?

Effectively, yes. But keep in mind, we're 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're driven by the actual data, that 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 a slightly increasing GOR, based upon the 2 or 3 years history that we have on the majority of our wells.

And we roll all that together and look a, kind of an overall average in that regard.

Can you guys talk a little bit about -- you mentioned that the workover and maintenance that you're doing on some of the wells and I don't know if that was Rick that referenced that and talked about some of the tubing. Or can you just talk about exactly what you're doing, the wells, and what vintage age that these wells are that you're performing the workover maintenance on?

Yes, David. The larger number of wells out there came from our acquisition.

So the workovers that we're doing are primarily in our southern acreage. It's -- but what we've been doing, that we believe are driving these costs, should drive the cost down over the long haul is, we aren't just going in and replacing in kind.

There was 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 pulled that 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 pipe back in the lower joints. But we're doing things that should bring down the failure rate, and that we're seeing results of that already.

So we're pretty encouraged about what we're doing.

And just keep in mind, that's not a bad -- we're not in a bad position at all on that. We're just trying to make it better.

And then on the China Grove acreage, could you remind -- when do you guys think -- and I think we talked about this last week, Randy, but when do you guys think we'll have -- you've got a handle on what you have up there? And then, I think your drilling at Cline well, is it perspective for any of other formations out there?

That acreage is -- we view it as principally a Cline play. There may be, there's lots to talk about in Mississippi, 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 buy outline, and our first well is -- horizontal well is being completed as we speak, early in the flowback. No meaningful data, positive or negative there, I don't think.

And I actually think, David, that we'll get this well on, we'll look at it a while, probably drill another 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.

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

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 getting a lot more information 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've got to do is raise the type curve, it increases the EUR.

But it really, it is too early to call that.

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.

And then just to 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.

We -- again, and I think we haven't seen enough data to change our model. We do have some spread on the results there.

There's some -- a well here and there that, for one reason or another, is 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, the Board will 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.

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 holding 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 confident that it needs to be adjusted.

Hey guys, going back your Permian-China Grove acreage, you kind of talked about the increasing industry activity in the area. Can you kind of touch on that a little bit, and what you're seeing up there from other operators?

Yes, 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've said this often, when started in Glasscock County, there was one other rig drilling, we brought in the second rig, and doubled the rig count, and now there's, I don't know, 35, 40 something rigs going there.

When we bought 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, and we're seeing that data from the other operators, and we're pleased to have it, and we're 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 have to be our drilling.

The first question's 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're in the 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 want it to be? Would you need to do something beyond that, or do you think if you were successful at selling that, those assets, would that take care of it for now or, so just thoughts around that.

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, thus funding a greater and greater percentage of that capital spend. So we don't feel that we're under any pressure, that we have to 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.

So Rick, so even though you don't honestly 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 to 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?

I guess in this role, you'd 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 2.6x.

It may go up slightly during the course of this year, but probably come down overall. I would say as it starts approaching, or if it started to approach, 3x 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 just really in fairly good shape for 2013, and we're looking at layering on additional hedges for years 2, 3 and 4 as well.

For 2013, we have a little over 60% of both our oil and gas volumes hedged at 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 1/4 per Mcf.

Just a couple of follow-ups. Randy, you mentioned multi-well pad in '13.

Is that the plan for all the wells, as you see it currently? Or 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 2, if that's the case?

Yes, and we haven't worked out the cost delta, so I can't give that to you. But I think -- 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 of each pad.

I think the way we view the derisking process, and the way we view the -- the way to approach is, we're still going to be drilling a fair number of one-off wells at 2013, 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. And it's going to take us, I think, several more years to really get to where the majority of it's pad drillings, so.

Thanks for the clarity there. And then on the workover expenses, those are a part of Q4.

Those are continuing in Q1 as -- and as we go through 2013 and I'm assuming if they do, they're already a part of the cost guidance you gave earlier?

Yes. They're -- those additional workover expenses are part of our 2013 guidance.

And that goes for the entire year? Or you think that those conclude at some point during the year?

I think our view is that we're -- what we're doing, over time, will get us in a position to where those wells don't need pulling units on [ph] in that area. But I think also, to be completely in line with the numbers of wells we're drilling, 700-plus producing wells out there.

I think over time, we're going to be lurking over, as they age, more and more wells. Thank you, Sue.

At this time, I'd like to thank everybody for their time this morning and their continued interest in Laredo. This concludes our call.