西南能源 (SWN) 2011 Q4 法說會逐字稿

Greetings, and welcome to Southwestern Energy's fourth quarter earnings teleconference call.

At this time all participant are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions) As a reminder this conference is being recorded.

It is now my pleasure to introduce your host, Steve Mueller, President and CEO. Thank you, sir, you may begin.

Good morning, and thank you for joining us. With me today are Greg Kerley, our Chief Financial Officer, and Brad Sylvester, our VP of Investor Relations. If you've not received a copy of yesterday's press release regarding our fourth quarter and year-end 2011 results, you can find a copy on our website www.swn.com.

Also, I'd like to point out that many of the comments during the teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors in the forward-looking statement sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe these expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

Let's begin. 2011 was another record year for Southwestern Energy. We set new records in production and reserves and as a result of our 24% production growth we achieved the highest earnings in cash flow in our Company's history. We produced 500 Bcfe driven largely by our Fayetteville Shale play where our production grew 25% to 437 Bcf. Our production from the Marcellus Shale also grew from 1 Bcf in 2010 to 23 Bcf in 2011, while our ArkLaTex production declined from 54 Bcf in 2010 to 40 Bcf in 2011.

Our year-end proved reserves also increased by 19% to a record 5.9 trillion cubic feet of gas. Approximately 100% of our reserves were natural gas and 45% were classified as proved undeveloped. We replaced 299% of our 2011 production, a finding and development cost of $1.31 per Mcfe, including revisions. This along with our all in cash cost of $1.27 per Mcfe give us one of the lowest cost structures in the industry. This year has already started out to be a challenge but as I tell our employers, our goal is not just to survive, it's to thrive.

Now I'll talk about our operating areas. In the Fayetteville Shale, we added 1.2 Tcf of new reserves that are finding and developing costs of $1.13 per Mcf. Total proved reserves, both in the Fayetteville Shale play at year-end 2011 were 5.1 Tcf, up 17% from the reserves booked at the end of 2010. We spud 580 operated wells in the Fayetteville Shale during 2011 and placed a record 560 operated wells on production, resulting in a gross production from our operated wells to increase from 1.6 Bcf a day at the first of the year to 1.9 Bcf per day at the end of year. We saw a continued improvement in our drilling practices in the Fayetteville Shale in 2011 as our operated horizontal wells are at an average completed well cost of $2.8 million per well. Average horizontal length of 4,836 feet, and an average time to drill of eight days from reentry-to-reentry. This compared to approximately the same cost in 2010 with a shorter lateral. We also placed 73 wells in production during 2011 that were drilled in five days or less. In total, we have drilled 104 wells to date in five days or less.

It's amazing that it has taken seven years since first production to transition the Fayetteville Shale drilling program from establishing first wells in the section to drilling multiple wells from a pad. Our average initial producing rates were approximately 3.3 million cubic foot per day compared to last year's 3.4 million cubic foot per day average rate. And in the fourth quarter of 2011 this average rate was over 3.6 million cubic foot of gas per day. Now, switching to Pennsylvania, we added 327 Bcf of new reserves, at a finding and development cost of $1.02 per Mcf. Total proved reserves booked at our Marcellus Shale area at year-end 2011 was 342 Bcf, up from the 38 Bcf booked at the year-end 2010.

As of year-end 2011 we had spud 70 wells, 23 of which were put on production, and 67 of which were horizontals. Total date of production from the area was approximately 133 Mcf per day at December 31 and limited by high line pressures. Our operated horizontal wells had an average completed well cost of $6.4 million per well, average horizontal lateral length of 4,007 feet, and an average of 14 -- of 12 fracture stimulation stages. The average gross proved reserves for the undeveloped wells included in our year-end reserves was approximately 7.5 Bcf per well and approximately 8.6 Bcf per well for our proved developed wells in 2011.

As for new ventures, at December 31, 2011, we had 3.6 million net undeveloped acres of which 2.5 million acres were located in New Brunswick, Canada, and the remaining approximately 1.1 million acres were located in the United States. In New Brunswick, we have invested approximately $24 million through December 31, 2011, and have acquired 248 miles of 2D seismic. In 2012 we intend to acquire approximately 130 additional miles of 2D, and our current plan includes drilling two stratigraphic well tests in the fourth quarter of 2012.

In our Lower Smackover Brown Dense Play in Southern Arkansas and Northern Louisianan, we hold approximately 520,000 net acres at an average cost of $375 per acre. Earlier this month we began pulling back our first well in the area, the Roberson 1819 number 1-15H, located in Columbia County, Arkansas. This well had a vertical depth of approximately 9,369 feet, and an horizontal lateral length of approximately 3,600 feet and was completed in 11 stages. The lateral was landed in the lower third of the zone and subsequent core analysis indicated this section had some of the lowest permeability in the entire interval. The well has been producing from 8 of the 11 stages fracture stimulated. It has produced for 20 days of the originally planned 20 to 30 day clean-up period. Oil production began on day eight with the highest 24 hour rates to date of 103 barrels of oil per day, 200 Mcf per day of gas and 1,009 barrels of load-water per day. 45% of the load has been recovered to date.

Our second well, the Garrett 723-5H number one located in Claiborne Parish, Louisiana was drilled to a total depth in February 2012 of approximately 10,863 feet, with a 6,536 foot horizontal lateral, and fracture stimulations are planned to begin on March 1. Knowledge gains from the first well allowed us to drill the second well with no troubles and led us to target the Brown Dense drilling in a lateral and -- no problems allowed us to target the Brown Dense. Drilling in the lateral was not only faster but oil shales and cuttings indicated better quality rock. We have also spud our third well, located in Union Parish, Louisiana, and is drilling at 7,900 feet. We are looking forward to learning more about this play, and our activity can increase dramatically if it is successful.

We also discussed that we hold 238,000 net acres located in DJ Basin in Eastern Colorado where we will begin testing a new, unconventional oil play targeting middle and late Permian to Pennsylvania carbonates and shales. The play ranges in vertical depths from 8,000 feet to 10,500 feet, and are within the oil window. Our primary Atoka/Marmaton objectives are alternating low permeability, 20 to 100 foot thick carbonates, separated by 10 to 75 foot think organic-rich carbonate mud stones with total organic carbon estimates ranging from 2% to 27%. Total thickness of the ejector section ranges from 300 feet to 750 feet.

This acreage was obtained for approximately $176 per acre and the Company's leases currently have an 85% average net revenue interest and an average primary lease term of five years, which may be extended for an additional three years. To date no production has been established in the immediate area. However, they're having mud log shows and gas shows, oil saturated cores and free oil on drill stem tests in the objective section. We have measured 36 degree API oil including inclusions and have seen micro porosity in both the lines and shale in the line sections as well as micro porosity in SEM analysis. The closest oil production from the objective formations is the Great Plains field, which is located 65 miles to the southeast in Lincoln County. The field discovered in 2009 has 12 wells and has produced nearly 1 million barrels of 36 gravity API oil from conventional carbonate porosity zones.

Earlier this month we submitted a drilling plan to the Colorado Oil and Gas Conservation Commission for approval to spud our first well in Adams County in the second quarter of 2012. This well is planned as a 9,500 foot vertical pilot well to the Lower Pennsylvanian Morrow Formation. The pilot well will be cored and then 2,000 lateral we drilled in a Marmaton objective. A second 9,500 foot vertical test is planned to the south which we will also drill to the Morrow formation and we will core the objective section. Again, if this drilling program yields positive results, activity in this area could increase significantly over the next several years.

You have probably noticed that I haven't mentioned gas prices. We are preparing for low gas prices throughout this year, as well as possibly for all of 2013. We will continue to be flexible with our capital investments and be sure that we are doing the right things with every dollar we invest. As a result we have decreased the 2012 capital investment program from our previous guidance in December. Currently we plan to invest approximately $2.1 billion in 2012, compared to the $2.3 billion plan we announced back in December. The decrease is primarily from the Fayetteville Shale program and the associated decrease in production is approximately 10 Bcf, or down 2% from the midpoint of our previous guidance. Gas production is not expected to grow at 13%. We will remain focused on keeping our costs as low as possible during this time and we'll remain vigilant in upholding our commitment to create value for every dollar we invest.

I will now turn this over to Greg Kerley, our Chief Financial Officer, who will discuss our financial results.

Thank you, Steve, and good morning. As Steve noted our earnings and cash flows set new records in 2011. As our strong production growth combined with our low-cost structure, have more than offset the impact of lower gas prices. For the calendar year, we reported net income of $638 million, or $1.82 per share, up 6% from the prior year. While our cash flow from operations, before changes in operating assets and liabilities, was up 12% to $1.8 billion. Operating income for our exploration production segment was $825 million compared to $829 million in 2010. For the year, we grew our production to 500 Bcf, and realized an average gas price of $4.19 per Mcf, which was down 10% from 2010.

We currently have 266 Bcf, or approximately 47% of our 2012 projected natural gas production hedged, through fixed price swaps and collars at a weighted average floor price of $5.16 per Mcf. Our hedge position combined with the cash flow generated by our Midstream gathering business provides protection on approximately 65% of our total expected cash flow for 2012. Our detailed hedge position is included in our Form 10-K filed earlier this morning. We continue to have one of the lowest cost structures in our industry, with all in cash operating costs of approximately $1.27 per Mcf in 2011, that includes our LOE, G&A, interest and taxes. Our lease operating expenses per unit of production were $0.84 per Mcf in 2011, compared to $0.83 in 2010. The slight increase was primarily due to increased gathering cost in our Fayetteville Shale play.

Our general and administrative expenses per unit of production declined to $0.27 per Mcf in 2011, down from $0.30 in 2010. The decrease was primarily due to the effects of our increased production volumes. Taxes, other than income taxes, were $0.11 per Mcf in both 2011 and 2010. Our full cost pool amortization rate also declined during 2011 to $1.30 per Mcf, down from $1.34 in the prior year. The decline was due to a combination of our low finding and developing costs and the sale of natural gas and oil properties in East Texas. Operating income for our Midstream services segment rose 29%, to $248 million in 2011. And EBITDA for the segment was $285 million. The increase was primarily due to increased gathering revenues related to our Fayetteville and Marcellus Shale plays, and an increase in the margin from our gas marketing activities.

At December 31, 2011, our Midstream segment was gathering approximately 2.1 Bcf of natural gas per day, through approximately 1,800 miles of gathering lines in the Fayetteville Shale play, compared to gathering 1.8 Bcf per day a year ago. Our debt to total book capitalization ratio declined to 25% at the end of 2011, down from 27% at the end of 2010. At December 31 2011 we had approximately $1.3 billion in long-term debt including $672 million borrowed on our revolving credit facility. In summary, our financial and operating results in 2011 were some of the best in the Company's history. We have the ability to weather the current low natural gas price environment, and cannot only survive but thrive in these times due to our strong balance sheet, the quality of our assets and one of the industry's lowest cost structures.

That concludes my comments and now we'll turn back to the operator who will explain the procedure for asking questions.

Thank you. Will now be conducting a question-and-answer session. In the interest of time we ask that you limit yourself to one question and one follow-up question. If you have additional questions, you may re-queue and those questions will be addressed, time permitting. (Operator Instructions) One moment please while we poll for questions.

Thank you. Our first question is from Scott Hanold with RBC Capital Markets. Please proceed with your question.

Thanks, good morning, guys.

Good morning.

Steve, can you talk a little bit about the well results? Giving the [Spackler] Play you indicated that low permeability in that lowest most formation? And, you're looking at the next well up a little bit higher. Can you talk about just on a relative basis what kind of perm you actually saw and how the upper members at that compares? And maybe put it in reference to some other unconventional plays to help us out as well?

Sure. We haven't got all of the information back on the cores for all the permeability. So, some of the statements I am going to make here are generalities from just a little bit of information. But, to remind everyone, as we looked at this play going into it, we were looking at on the low side, 0.1 microdarcys. And then we had as high as 2 or 3 microdarcys-type rock that we were looking at. The core had some very good permeability in the upper part of it and to put it in kind of a relative sense, the lower part was on that lower end of the microdarcy range, the upper was almost 5 times as good as the lower portion as you looked at it.

Now, one of the questions you asked was, why did we land in the lower part of the well? If you remember going into this well, we didn't know what the fractures were going to do and we were about 500 feet away from a wet zone that we didn't want to fracture into. So we intentionally landed as low as we could in the zone, drilled out the lateral and then the very first test we did if you remember, we fracked three stages and just flowed those back to see if we were getting any unusual water. We weren't. We did micro seismic on the three stages. We went back did the other eight stages for a total of 11 stages, micro seismic on it. And now that we've got the micro seismic in, we've seen that we've only extended up our fracs, somewhere around 100 feet to 150 feet above. So we didn't even get into the better rock with the fracs that we did in the first well in the first zone.

So, we are excited about having 100 barrels a day coming out of the rock we have at some of the lower permeability rock that's out there. It would be the lower end of either the Bakken or Eagle Ford type rock. And we know we've got some better rock up above us. The second well in Louisiana, now you've got to remember your roughly 30 miles away, the actual porosity in it and permeability is thicker than in our first well. And there's some geologic reasons we think that happened in that direction. But we were able to land it in the top 50% and basically roughly the top third. And what drilled much, much faster and looks much better overall. To the point that in the first well, while we had good shows while we are drilling it, the shows we are seeing were just fluorescents. In the second well we actually had a little bit of free oil on the pits. So both of those have a little bit of difference to them as far as that goes.

Okay. Okay. That's good color. And in terms of like - - I guess that you had about 1,000 barrels of water load on this one. What are you expect for that second one, being higher up it doesn't sound like you are concerned about fracking into any kind of water. But, what would you expect, if you put a stronger frac on this, do you create a better flow rate from the oil? And is there any risk then being higher up that you're going to frac into the ocean above?

I don't think there's any risk that we are going to frac in the ocean because, again, that last frac only extended 150 feet at the most up. And while we've landed right now, if it extends 150 feet up it barely gets to the top of the zone. So, that's not an issue at all from a fracking standpoint. You need to remember that second well is a 6,500 foot lateral. We will frac it very similar to the first well as far as number of stages per so many feet of lateral, roughly 400 feet apart on the stages. We will roughly do three to four per foot intervals before each stage. So we'll end up with over but 20 stages of frac on the second well. So, even if it was the same quality rock I would expect to get much better rates.

Now the other part of your question was, I think having to do with how much water should we expect when this is all done. And, we don't see from core analysis that much water in the formation itself. But, that's one of the things we are trying to learn. We don't know what the amount of load water we ultimately have to get back before it's completely cleaned up. We know we're at 45% now on the first well. We do know that as load water's gone down, it took to the eighth day to start to see the oil as the load mark continues to go down, the oil continues to go up. So all of that is still progressing but there will be a point in here, even on the first well or any of these other wells we drill where we will determine how much load water gets left in the formation, how much we can actually get out, and what the ultimate oil versus either gas or oil versus water rate is.

Okay. No, that's great. Thanks a lot, guys. And are you going to press release the results of that well? Or are we going to wait - - is it like your next quarterly update? How is that news flow going to come out?

We don't like press releasing wells. So my guess is we will wait until the next time we have something to talk about something else, whether it is the end of the quarter or something else we have to talk about.

Fair enough, thanks.

Our next question comes from the line of Gil Yang with Bank of America-Merrill Lynch. Please proceed with your question.

Good morning. Just to continue along the Brown Dense. Can you talk about what you saw in terms of API and sulfur for the oil and in both - - in all three of the wells that you've seen information from so far?

Were looking at mid-30 APIs, 35 APIs, 36 gravity API oil. And that matches with the well test that were in the area before. If you remember there's some vertical wells that we had some tests on. And so from that standpoint, oil looks about the same as any of the other ones out there. On the H2S side, we're still trying to get a handle, there are days we get little whiffs of H2S. And then other times we get almost no H2S. But right now it doesn't look like H2S is significant in any of the wells that we've drilled or where we're at to date with the two wells.

And then we do have a little bit of CO2 that we are seeing in this well. And again, because we haven't got all the water lifted off of it, we don't know if that's going to stay in the well or not. But there is a few parts per 1 million of CO2 as well.

Okay, have you seen the CO2 in the vertical wells that you looked at?

They didn't report any. And again, those tests went from 1946 to like two years ago. The only really good information was the ones a couple of years ago and there wasn't any on that. CO2, if you have some kind of reaction at all with the carbonate that's in the formation, CO2 is just one of those things that comes with that. And so as we frac the well, we could have easily had a little bit of CO2 just as part of that frac process, and once the well cleans up you may not see CO2. On the other hand, there may be just a little bit of CO2 with the gas.

Right. And just sort of a separate question is, can you just talk about the negative revisions on performance in the Fayetteville in particular. But both for the two areas where you reported that?

Well, I think the easy answer on the whole thing is there's all kinds of things that go into the various wells, but the easy answer is that it is mainly price. But because we're about $0.12 difference from year over year. I will say in the case of the Fayetteville Shale, we took a little bit different approach to how we are doing our reserves this year and that fine-tuned the whole project for us. And fine tuning we had a bunch of wells that were a lot better and we had a bunch of wells that were a little bit less and it kind of averaged out to that. So there isn't anything more than that.

Okay. So what you're saying is that the negative revisions where to a large degree more, the really price revisions not performance revisions?

The biggest negative revisions anywhere as in our Arkoma. There's one field called the Overton Field and some wells fell out because of price, and there was just some production revisions there. But, like I say, that there's not much there one way or the other on the revision side.

All right. Thanks, Steve.

Yes.

Our next question comes from the line of Brian Singer with Goldman Sachs. Please proceed with your question.

Thanks. Two questions. The first is continuing on the Brown Dense. When you look at the lower portion that you did frac into, what are your thoughts on both oil and place, or more importantly, recovery rate? And does the low permeability you saw there condemn up to a-third of what you thought was theoretically possible previously?

We're trying to figure that out, Brian. One of the things we do with our first well, and really first, second and third well are offsetting within a mile or so, some of these vertical tests that were done. And this first well we offset about 1 mile, 1.5 miles away from another well. Is was actually drilled on top of a structure. And that original well was drilled on that structure as well. It looks like that on the top of that structure geologically the rock did not, at least the history of the rock, wasn't the same as opposed to the rock that is off the structure.

So, as you get over towards our well we drilled in Louisiana and some of the other wells around there, that section that has good porosity actually gets thicker. So, and our second well almost 70%, 75% of the section has that high porosity in it, where in our first well was almost 50-50. So as far as oil in place, certainly the tighter the rock, doesn't change so much the oil in place but your recovery will change on that. And we are just going to need some more wells to figure out how variable that is and just figure out what is going on from there.

Okay, thanks. And my follow-up is in regards to the Marcellus. Can you just compare and contrast the well results that you are seeing recently in Bradford County versus Susquehanna County?

Well we don't have any wells yet put on production in Susquehanna County. When we talked about all those wells that we drilled, we'll see our first Susquehanna wells come on production in sometime the middle of March. So I can't tell you much about those yet. And Bradford, we have a variance of those wells. And I think the best well we have is probably well over 15 Bcf and we talked about the averages but I think the lesser of the wells we have out there are probably about a 5 Bcf well in what we've seen. And they're really, as far as where is better and where is worse and - - we haven't seen that, that pattern yet to know exactly on a same pad, where we drill three wells, it could vary from 6 Bcf to the 10 Bcf or 12 Bcf range.

That's great, thank you.

Our next question comes from the line of Marshall Carver with Capital One. Please proceed with your question.

Yes. I have a couple of questions on the Fayetteville. You booked 2.4 Bs per well. When I look at that type curve plot that you provide, and you show the curve with the wells over 4,000 foot laterals. And almost all the wells you're drilling are 4,000 foot plus. It looks like your wells are tracking over a 3 Bcf-type curve but you are only booking 2.4 and you didn't have many positive revisions. So, what should I think about the difference between the type curves you are providing and what you're booking?

There is a few things to think about there. First off, when you think of our reserves, remember the definition of proved undeveloped has to be your 90% certain. So, you're going to take your distributions and pick a median rather than an average to start with. Secondly, all of those curves that we have in our literature for the most part except for just a little bit of drilling last year, were drilled on that mile apart spacing as we were doing our first wells in a section. And we've always said as we get to our pud drilling, what's going to happen is you're going to have 10%, somewhere around 10% interference in ideal case. So what you need to do is back off of that. And again, if you back off what would be a 3 Bcf leg and about a 2.7 Bcf well, now you say you want to be conservative, you're down that 2.4 Bcf to 2.5 range as far as that goes.

The other thing to keep in mind is, you book around where you drilled during the year. And if you remember, we spent a lot of time during year proving up acreage on what I call the edges of the field. And that is where we booked our wells as we put the wells out there. So there is a little bit of distribution of wells. We only have around 1,600 wells total book as far as puds. And so there's a little bit of location this year versus some of the other years as well that goes into those pud bookings.

Okay. That's very helpful. Thank you. And a follow-up on the - - you talk about the PVI hurdle, and not wanting to drill wells that are below the PVI hurdle. Is the Fayetteville with current gas prices is the Fayetteville below that hurdle now? And if so, would you potentially reduce activity more if gas stays around $3? Or are you drilling better locations to make sure you hit the hurdle rate?

What we've done with our 2012 budget besides cutting back a little bit in the Fayetteville Shale from where we originally announced, we are also changing to the point where we are going to drill the very best wells. And again, on any of these plays, and we just talk about in Pennsylvania, you got distribution of reserves, and you've got some very, very good wells and then you've got some lesser wells in there with some kind of average. But what we've talked about in the past that to drill our average well we need around $4 price.

But we have at least a couple years worth of wells that we can drill if it stayed $3 flat forever in the Fayetteville Shale, and that's what we are doing. We're drilling those very best wells. You may see little bit of inefficiencies in what we are doing as rather than drilling all the wells from a pad at one time, we'll go in and drill the best well off the pad and then move to another one. You also see us widen out our spacing a little bit here to make sure that we get better wells. And then we'll come back later in put some more end fill wells into that overall spacing. So we are adjusting our program but certainly, if it's $3 flat forever, we've got wells to get us through this year and into next year and we're looking for other ones beyond that.

Okay, that's helpful. Do you have a feel for the - - about how much better on average the wells would be that you are drilling this year versus last year? In terms of EUR or IP?

We're going to need those 3 Bcf wells you were talking about.

Okay.

So that's what we are shooting for, it will be plus 3, plus 3 going on plus 3.5.

Okay, thank you very much.

Our next question comes from the line of Joe Magner with Macquarie. Please proceed with your question.

Thanks for taking my question. Just noticed that the new ventures budget has dropped meaningfully. Just curious what the underlying drivers or revisions for that budget were? Is that to account for less drilling? Or, reduced expectations around new programs? Just a little more information would be helpful.

What we did was, we had put in some dollars for some new plays in the budget and expanding some of the plays we are already working on and we backed off on that. That's where most of the back off is. And then we're watching the Brown Dense close, but we assumed we would do one less Brown Dense well that we said to prove it up. And we did that on the assumption the industry was going to drill wells around us and be able to do that.

So, there's at least one well less and then some acreage. And we'll just look at that and play it out through the year. If we come up with a really good idea were not going to slow down picking up that acreage on a good idea, especially if it is an oil idea. But that's where its at. It's really not changing any of the drilling we want to do this year or the plays that we're getting close to finishing on, it's not affecting those at all.

Okay, and then on the new DJ Basin opportunity. My understanding is that the wells that have been drilled in that Great Plains Field were vertical wells. Can you just I guess provide a little more information on how you decided to target horizontal in the Morow section?

In the Marmaton?

Rather the Marmaton section? And then just kind of what the overall geological setting is that is being pursued there?

All right. To kind of get everyone in perspective, you hear about Niobrara Play, this is deeper than Niobrara, it's in the Pennsylvania and H section. There's the Marmoton, our Atoka interval, roughly in that 8,000 foot to 10,000 foot depth range. The field that we talked about is the Great Plains Field, is quite a ways away, it's almost 65 miles away from where we're drilling our first well. And as you said, it's drilled and is being developed vertically. And the reason it's being developed vertically is there is over a 2,000 foot section of potential rock interval and there is in that anywhere from 300 feet to 700 feet of potential pay that's within an interval.

Their best well in that field has - - was drilled back in 2009, it's already produced to 247,000 barrels in 20 months and it IPd at 1,500 barrels a day, that's 24 IP, first 30 days was 634 barrels a day. So there are some very good wells in that field. There is also some other wells in that field that their 30 day rates were as low as 100 barrels a day. So there is a lot of variability and therein lies the thought behind doing a vertically versus doing horizontally. We may end up ultimately having a vertical play here. But, we think we've identified a couple of fairly thick zones in our acreage that would lend itself well to horizontals. And if there is a lot of variability in the lateral sense, if we can do it the horizontals we might be able to streamline some of that range they see in Great Plains where they have 100 barrel a day wells and then they have 1,000 barrel a day wells there.

So, I don't know what the ultimate answer is going to be whether it's going to be horizontal or vertical. But we will start that first well will be drilled through the whole section. We will put a short lateral to see what happens in specifically in the Marmotan interval. And then that second well is actually planned to be a vertical well. So we're still playing with both of those as we go through. The other thing just to note is that while Great Plains Field is the closest field to what we're doing, there is 96 wells in the immediate area in Southeastern Colorado that have produced out of the section. So it is well known by the industry. It is only in the southern part of the state and the very north end of our acreage gets on the edge, it won't be the Niobrara Play, but we really don't have the Niobrara section on our acreage. This is that deeper Pennsylvania section for anything we are doing.

So this is more like a sort of Texas Panhandle stack wash opportunity?

Yes, some of the sections almost identical to what's going on in the Panhandle but, yes, that's exactly what it is.

Okay, I will leave it there. Thank you.

Our next question comes from the line of David Heikkinen with Tudor Pickering & Co. Please proceed with your question.

Morning, guys. First question just thinking about the lowest macro over Brown Dense. Does the first well confirm or eliminate any acreage?

Not at this point, it doesn't.

Okay. And to be clear the frac of the water that you are producing is from the frac load not the reservoir currently?

Yes.

And what percentage of frac load would you expect to be able to recover in kind of in that 30 day window? Or do you think it's going to take longer than 30 days now?

It looks like it will take longer. I don't know. I just don't have a good feel for that. Were continuing, as you saw we are still getting 1,000 barrels a day of fluid back. So, it's not cleaned up yet and it's still giving us frac fluid back. So, I don't know, is this going to take 45 days, or 60 days, or 90 days, I just don't know.

I guess it would be hard to predict what a stabilized oil rate would be as well given - -?

I can't even start guessing yet.

Exactly. Thinking on another, on the Midstream, do have a thought around what the industry-wide, or gross exit rate would be for this year, for your Midstream business?

I would say and what you're asking me to do is kind of predict what - - besides what we are going to do, predict what the rest of the industry is going to do. I think we're seeing a slowdown in the other industry partners as well. But I haven't heard any exact announcements to know how much slowing their slowing down. If you step back to October, November timeframe, both the other major players, BHP and XTO, were actually going to add rigs. And it looks like they're going to add eight rigs in areas where we were going to be gathering gas for them. Today, we are getting indications that if there is any rigs added they are not going to be drilled where we're gathering. So I would guess that through the year we'll have a little bit of decline in our third-party gas where today it's about 170 million to 180 million a day. It will probably decline some, maybe 150 during the year. And then we will be growing our production in the Fayetteville Shale in a double-digit kind of rate. So, whatever that comes up as a 2.3 Bcf to 2.4 Bcf day, somewhere in that range, 2.2 Bcf, I don't know.

All right, thanks. I've enjoyed following you over the last 12 - -.

Good. It's great to hear from you, Dave, and good luck.

All right, thanks a lot.

(Operator Instructions)

Our next question is from the line of Dave Kistler with Simmons & Co. Please proceed with your question.

Morning, guys.

Good morning.

Real quickly, with the adjustments to the capital budget that took place pretty rapidly here with fall down in gas prices, how quickly would you look at revising that back up where if gas prices were to start to improve in the second half of the year? And where would you direct your first dollars as you put capital back to work?

I sure hope we come across that situation where it comes up in the second half of the year. But, I think we're expecting that we're in the price range we are going to be through this year and the next year. The real key for adding anything back is what you think the long-term price is going to be. And so, even if it jumped up for a short period of time at the end of the year, I don't know that would make us change our mind. But if we started seeing the fundamentals changed so that we could get something above that $4 range, certainly then you would see us add. Of the things we have in hand, we really would like to accelerate Pennsylvania no matter what the price range is. But, what's limiting us in Pennsylvania right now is our firm capacity and were following that curve with the rigs we have. We're working hard on adding more firm and so you may see us even redirect some more capital in that direction during the year.

Certainly on the new ventures, any of those come in, those are oil, those are different price dependency, you could see us do some things. And in the Fayetteville, we are doing things to get our cost down. And one of the things we're doing is we are going to go into the pumping business and so we are going to further vertically integrate. We will have two units that we operate, in operation by the end of the year. And we should save ourselves about $140,000 per well on the wells that we are drilling with our own pumping equipment.

So, in that case as we cut the cost down, then we might be able to add some rigs back in. And then the other thing we're watching closely is just how fast we are drilling. In the December release we said that we were going to drill in basically mid-seven day timeframe. We are beating that right now. So, that while we are dropping rigs, the well count isn't dropping as fast. So, we have to watch that, too. But all of that we will watch as we go through the year. And then we will either add or subtract as the year plays out or as 2013 starts to unfold.

Okay. And then as a follow-up, a little while back you guys indicated that at $3 gas you figure you have about 1,200 well locations in the Fayetteville, down from say 8,000 locations at $4 gas. If we use sort of the same price mechanisms to think about maybe where year end prices might end this year, I wouldn't imagine it would be a one-to-one decrease in your proved reserves as a portion of it would be proved developed producing. But what kind of a decline do you think you would have on your reserve base under that sort of scenario where it went from $4 to $3, and you're identified locations dropped by 70%, 75%?

It would be challenging, and I don't know the exact answer. We have not gone through that calculation. But, everyone needs to think about the fact that now that you do reserves on a rolling 12 month average, as we've been going to the second and third quarters, you're going to start seeing higher numbers last year roll off and lower numbers this year going into that average. So, while year over year there was always something like $0.15 or $0.16 difference in average price, that is going to decrease significantly by the time you get to the summer just with the first three months of this year as you go through. So, I think all of the industry is going to have some challenges on what they can book and not book. But, we haven't done enough now to be able to tell you what the issues are going to be, I just know there are issues coming up.

Okay, I appreciate the added color. Thanks, guys.

Our next question comes from the line of Robert Christensen with Buckingham Research Associates. Please proceed with your question.

Good morning, Steve. Two questions. The first is can you give us sort of your logic as to where you go in the Lower Smackover? You started with Robertson, you go to Garrett, BML was chosen third, and just the logic of going around sort of that triangle? Why first, why second, why third?

We picked Robertson where we did, we thought it was a little bit - - it wasn't quite in the center of the oil window but close to the center of the oil window. It was offset by some of the best control that we had so we can land the lateral and knew we were going to hit the lateral. Again, we don't have 3-D out here. So, though we had a lot of wells that were drilled because there on top of the structure, we had a lot of wells that were drilled to the Smackover that we could go off of. And then the thought was move into Louisiana, stay in the oil window and just get a distance away, near another well that had been tested before. And that was what we did with the second well. The third and the fourth wells are similar to that, we will be offsetting or near wells that have been drilled in the past but spacing ourselves out. Just to start seeing the rock characteristics but for the most part staying within what we think is the obvious oil window.

And then when we originally put the program together for a total of 10 wells, to six wells after that, the two things that we were going to do is start driving cost down on the wells themselves, those first four. There's going to be a lot of science but then we're going to lessen the science as we went through the other ones. And we were going to start pushing the boundaries of the oil window either up dip or down dip. Up dip as you get towards immature oil and down dip as you get towards the gas part of it. That's all going to change and really even our fourth well today is in limbo, exactly where it is going to go. And the reason it is changing is that the industry is also drilling wells.

So to the extent that one of those wells we were going to drill somewhere in our sequencer close to one of the industry wells, we are busily making agreements with industry to trade information. So I can tell you the first three are still under that same logic that we had, but from four on, we're revising it as we see other information come in.

And how many wells do you think the Company will now drill this year in the Lower Smackover Brown Dense?

I think what we have in the budget right now is five wells. Five wells drilled this year, total of six wells. But, we will drill what we need to drill. And so if the industry gets some more wells downs and we can learn the answer without having to drill as many, fine. If we need to drill some more, we'll do that. And we'll just adjust our budget to where it goes. But, right now, six total is what we are thinking about.

One follow-on if I may. When you express that the oil shows in the second well is actually turning into oil in the pits. How much better I guess is the porosity and permeability associated with that statement compared to the statement that we just saw florescence in the first well? Can we see quantity through that lens, if you will, that you offered us?

I think you can start getting indications of quality as you know, shows have a lot of variables with them. What your mudway was, what the kind of mud your using, and how fast you are drilling. So there's all kind of things that go into that. But the second well drilled much faster with basically the same mud than the first well. That tells you that there was a different rock there and then probably had more porosity and permeability indent. And we did see more oil so that tends to indicate more permeability. And when I asked our guys that exact same question and pressed them on it, they said, well it looks about five times better than that lower zone on the first well.

Now that's all relative. Is it five times better, eight times better, or three times better, it's just better. You don't have enough information to know. And we don't have the ability to get chips like you do in conventionally. You would be able to get some chips from down hole and you would be able to look at and compare it. In our case the way we are drilling, it's very difficult to get chips, but you have to send it to a lab to even look at the porosity or permeability that's in it. So we've got a core, the core is being analyzed right now and soon we'll know the difference. But it's all relative at this point in time.

Thank you very much.

Thank you.

Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Please proceed with your question.

Gentlemen, good morning. Recognizing the data you are working with is limited in that it is early innings, how does the Brown Dense rank versus the new DJ Basin venture and anything else in the new ventures portfolio at least in terms of resource potential and what's economically recoverable?

I can certainly compare the Colorado and Brown Dense. And in the case of Colorado you have had commercial production from that interval at least in the vicinity of where you're at. And it doesn't have as many tests in the area. There is only four wells within an area that we are buying acreage that have gone into that zone. But that did have shows and those kinds of things on it. But since you have commercial production I think the real issue in Colorado is the variability of the rock and can you get consistent commercial production.

In the case of the Brown Dense, the Brown Dense is much bigger. We've got 238,000 acres in Colorado and that will grow some but it will be in that 250,000 260,000 range. In the case of Brown Dense you've got over 500,000 acres in roughly the same thickness objective interval. They are space that differently but roughly the same. So the Brown Dense has a lot more in place to go after. But it's going to take a lot more to figure it out though, because it's a bigger area. So going into the Brown Dense we had really three big issues. How does it drill. When you frac, will you get into the water that's above it? You don't have that problem in Colorado. And then can we make it commercial? We know we can drill it now. The second well drilled much, much faster. The third well, we're blowing that one down, we are getting the pace done. We think we know where to land in the Brown Dense, but we still have to figure out commercial there. So that's kind of the differences.

Okay. And then a follow-up. On the Brown Dense itself and specifically the Union Parish well, how does the rock change moving west to east? How does the risk profile change, that is? And how will that well be completed? Will it be completed any differently than the first two?

We are still looking exactly on how the well is fracked. But basically it will be completed the same. It will have just more fracture stages because it is a longer lateral. And the third well, by the way, we are going to try to do that. That is in Louisiana also. That's going to be a 9,000 foot lateral. So that's even going to have more stages in it. But right now we will frac them basically the same, with just minor variations just to see the differences. So we can really tell the difference in what's going on with the rock, not the difference in how we are fracking them to start with here.

As far as the way it looks in the rock, it's a little bit thicker as you go to the East. So it's probably 75 foot to 100 foot thicker in general in our second well than in the first well. And again, that first well is over 350 foot thick. So it's a very thick interval. When you look at a log that is drilled through it, there is a distinct log characteristics that we are trying - - we think we have figured now that shows the better porosity rock versus the tighter rock. And we are in the early stages of understanding this.

So I want to emphasize that we think we are getting to understand it. But if we are understanding it right, certainly the logs are about twice as thick for the good interval in the second well than they are for the first one. But, again, second well we've got a core in and analyzing right now. First well, we haven't got all the permeability's back on it, so we've still got some things to look at before I can pound the table and say it's definitely getting better in one direction or the other. We do know if you go far West, if you go over toward the Louisiana Texas line, you're getting deeper the rock is higher temperature, more cooked and you get into gas. So in general, the oil window is going to swing around from the Arkansas down into the Louisiana in general.

Thank you.

(Operator Instructions) Our next question is a follow-up question from Scott Hanold with RBC Capital Markets. Please proceed with your question.

Thanks. Steve, you mentioned about investing in some pressure pumping. What are the plans there? How much horsepower are you looking to add? And what's the CapEx on that spend this year?

We will basically do two frac spreads and I don't know off the top of my head the exact horsepower. Total investment will be probably about $65 million for the two frac spreads. And we'll have them operational hopefully in November timeframe of this year. So it's really a cost savings for next year. As far as the capital budget, in the original capital budget we had put $50 million in thinking the frac spreads would be done in early 2013. We count it as capital. In this one with the reduction of the $200 million, we've taken it completely out and we are going to finance that through releasing. So it's not a capital item right now the way the budget sits.

Okay. So it's not in your budget?

Correct.

It's a lease back? Okay. And then can you talk about the Fayetteville rig count right now? So are you running 11 rigs now? And there had been plans to drop one, and then is two others coming off? Can you kind of give us the timing of that? Or tell me if I've got that right?

We're working on that. There is 11 today. One will drop in the next week or two. Then, what I think you'll see between now and sometime in July, we'll drop three more at least and possibly four more rigs. I say three more, three more from the 10 and then going down to seven, four total, rigs more out today. And we're still trying to get the finals on that. So and we may run one rig a little bit longer as we look at it. But, that's roughly what we are going to do. Exit the year running seven big rigs in the Fayetteville Shale.

Okay. And would production in the Fayetteville grow at that point, or will it be fairly flat?

It will grow through this year. If you continue running seven rigs into the future, it flattens out pretty fast.

Got it. Thanks.

Our next question is a follow-up question from Robert Christensen with Buckingham Research. Please proceed with your question.

The fourth well I thought was back up in Arkansas. Was that the case? Or - -?

That's the way it has been planned, yes.

And the follow-on would be - -

Let me add one more thing in there, Bob. On that fourth well, originally it was planned to be very close to where Cavitch just recently drilled a well. So as long as we can get the information from Cavitch, if it's in Arkansas, it won't be where we originally planned it, I can tell you that. So we are still looking at that.

All right. And if the formation thickens up enough as you go further to the east, would it ever make sense to maybe drill just a vertical well, and fracture stimulate that first? As opposed to going horizontal from the get-go?

We don't think that that will work. But, we need to get some core information back. I won't say you would never do it that way. But when you just look at the advantages - - on that second well it took us about 14 days to drill that 6,600 foot lateral that's out there. I know we can decrease that time. And if you are down at 10,000 feet you might as well take the few days extra it takes to drill the lateral and then add the fracs and get the added advantage to that. But we will certainly look at it just like we would look in Colorado which is the best way to do it, vertical or horizontal.

So, the second well, what was the total time to drill because you were a vertical for - -?

Roughly, 50 days. Give or take, I don't remember if it was 50, 53, something like that.

50 days all in for the second well?

And what the rough costs on the difference between the first well and the second well would you estimate? Is it a big step up? Or about the same?

All of these wells, the first four that are going to do the core and all the science would be above $10 million. The first well we actually got out I don't remember if it was quite 2,000 feet and wasn't where we wanted it to be and had some problems with the well and backed up and redid the sidetrack. So that first well is probably $2 million, $1.5 million to $2 million higher than the second well just on redrawing the lateral. But ultimately, we think we can get these down in the $7 million to $8 million range is what we are shooting for.

Do you think the second well is going to be more costly than the first well?

No, no. The second well will be cheaper that the first well by about $2 million, at least.

Okay. Well, thank you very much.

Thank you.

Our next question is a follow-up question from Gil Yang with Bank of America. Please proceed.

Steve, you mentioned that you're going to drill a couple of stratigraphic vertical tests in New Brunswick. Can you just comment on sort of what you're looking for in those kinds of wells. What we should expect you to learn from those wells?

Sure. In New Brunswick, we need to get this other seismic shot. But if you think about the sequence we've done, we think we found a new basin. We did a bunch of work to prove that it was there, we shot seismic, we need to get a little bit more seismic done to the East that we didn't get done in 2011. And the whole idea was to identify where the basin deeps were, where the - - if you spot any highs and then pick a couple of wells that could tell you actually what is in the basin.

At this point in time, you've got rock that comes to the surface north of where the basin is at. You've got a basin to the south that's got some wells in it. But these basins have no wells whatsoever. So at least from one of those stratigraphic tests will be one of the deepest parts of one of those basins. You'll just drill right through the whole interval to try and figure out what's there. Is the shale (inaudible) there, or not? Is there any conventional targets that are possibly there? So you would just look at a section. The second well, depending on exactly where you are at, may have some other target to it where you've seen something on the seismic that you want to investigate. But both of them basically are just trying to figure out what the section looks like so you can tie in more data so later you can then come back and actually drill wells that would have hydrocarbons as the objectives.

Okay. So it's basically to provide the subsurface data that ties you to the different horizons you're seeing on the seismic, right?

Right. And just to give you an example, while you see events on the seismic, you are just guessing at what the velocity is, or what the depth is because you haven't got any data to tie it to and the nearest data is 60 to 70 miles away. So that first well just lets you tie that in. It will let you figure out how to redefine your gravity and magnetics that you work on the basin. So you will get that information, redefine everything again, and then you'll actually start drilling for true objectives.

Right. Another follow-up, I think in your previous budget you had said that $4 gas. And you, however, very good in giving sort of the guidance based on the sensitivity based on different commodity price assumptions. And it looks like the current budget based on that is announced then of maybe $400 million, $500 million based on $3 gas. Is that a fair assumption of what you are pricing in this budget?

It's in that range, I don't know if it's quite to the $500 million range, but it's in that range.

Right. But the basic assumption is your sort of assuming $3 gas?

Yes.

Okay. Great. Thank you.

Our next question is a follow-up question from Joe Magner from Macquarie. Please proceed with your question.

Thanks, just one quick follow-up. You mentioned that you had taken $65 million out of the budget for spending on the pressure pumping equipment. Which bucket did that come out of? It doesn't look like there was an obvious drop in midstream or other. Just curious where that might have shown up prior?

That was actually in the Fayetteville Shale.

Okay.

It was about $50 million. Again, we thought we weren't going to get equipment until early next year. Now we are much more comfortable that we will get the equipment this year. So $60 million was total, $50 million was actually in our budget.

Got it. Thanks. That is all I had.

Ladies and gentlemen, we have reached the end of the question-and-answer session. I would now like to turn the floor back over to management for closing comments.

Thank you. We've had a lot of discussion today about the Brown Dense. Had some discussion about Colorado. But what I want to leave you with is we are very proud of what happened in 2011. And we especially want to thank all of our employees, we've done a great job. When you think about the Fayetteville and Marcellus, I wouldn't want any other assets in today's price environment.

We know we can overcome the challenges of those assets as we look out into 2012 and even as we look out into 2013. We know we can deliver for our shareholders in those events. And then we're really excited about 2012. Brown Dense, first well, a lot of questions answered, a lot of questions asked. We're getting ready to drill in Colorado. I am sure that will be the exact same thing, where those first few wells we will be asking as many questions as we answer them.

But these are quality plays and there is the kind of a things to expect from us as we look out into the future. We've got New Brunswick coming up and then we're still working on some other projects. There's still some of that other acreage we haven't talked about out there. So we're really excited about 2012. This is a year for us to thrive, this is a year irrespective of what gas prices doing, irrespective of what oil prices doing, irrespective of the costs that we think we can deliver for our shareholders and we're just looking forward to updating you in the future on that. So, thank you, and this concludes the conference.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation. Have a wonderful day.