西南能源 (SWN) 2010 Q2 法說會逐字稿

Greetings, and welcome to the Southwestern Energy Co. second quarter earnings conference call. At this time, all participants 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 Chief Executive Officer for Southwestern Energy company.

Thank you, and good morning. Thanks, all of you, for joining us. With me today are Greg Kerley, our CFO; and Brad Sylvester, our Vice President of Investor Relations. If you have not received a copy of yesterday's press release regarding our second quarter results, you can call 281-618-4847 to have a copy faxed to you. Also, I would like to point out that many of the comments during the conference 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.

To begin, we had a very good second quarter in 2010 and made progress on many fronts. Our operations in the Fayetteville shale are on track, as evidenced by the 32% growth in Company production compared to last year, and by 9% sequential growth. The previously announced sale of a portion of our Haynesville and middle Bossier properties in East Texas closed for approximately $355 million and finally, because we're improving results on the Fayetteville, our production guidance is unchanged for the third and fourth quarters of 2010 and our capital investment program also remains unchanged at approximately $2.1 billion.

Now to talk about each of the operating areas, last week, our gross operating production from the Fayetteville shale exceeded 1.4 Bcf per day, up from 990 million cubic foot per day a year ago. During the second quarter of 2010, our horizontal wells had an average completed well cost of $3.1 million per well, average horizontal length of 4532 feet, and an average time to drill to total depth of 13 days from re-entry to re-entry. In the second quarter, we had 22 wells with drill times of over 20 days, most of which were first wells and sections that were in the deeper southern areas of the play.

On the flip side, we placed three wells in production in the quarter with average times to drill the total depth of five days or less from re-entry to re-entry. In July of 2010, our average time to drill to total depth improved to 10 days from re-entry to re-entry and we set a new record by drilling a well with total footage of 6600 feet in four days. Because of our recent faster drilling times we are dropping horizontal rig in August, reducing our horizontal rig count to 15 rigs in the Fayetteville shale.

Our Fayetteville shale wells placed on production during the second quarter of 2010 averaged initial production rates of 3,449,000 cubic foot, upper day, up 8% compared to the first quarter. Results for the second quarter included 75 wells placed in production, which were first wells in the section. We also placed nine wells on production with initial rates over 6 million cubic foot per day. We continue to test tighter well spacing and at June 30, had placed over 430 wells on production that have well spacing of 700 feet or less, representing approximately 65-acre spacing or less. Recent information from these larger groups of wells indicate interference of 5% to 8% compared to earlier estimates of 10% to 15% from the smaller well set.

As you recall from last quarter, our 2010 drilling program includes testing over 44 different pilots with well spacing that will range from 200 to 450 feet apart. Within these pilots, approximately 67% of the wells have been spud and 23% of those wells have been placed on production. Because of the small number of wells and the short time on production of the completed wells, no conclusions can be made yet about any new spacing.

Switching to East Texas, as I previously noted on June 30, we closed the sale of certain oil and gas properties, leases, and gatherings equipment in Shelby and St. Augustine counties for $355.8 million. The sale included only the producing rights for the Haynesville and middle Bossier shale intervals and approximately 20,000 net acres. We retained the drilling and producing rights, covered all depths in the acreage, including our James Lime and Pettet drilling programs. We still have approximately 10,500 net acres with Haynesville and middle Bossier potential and drilled two wells on this acreage in the second quarter. The Tim Star, Blackstone, A1H well targeting the Haynesville shale formation has been drilled and is currently being completed and the Harris B1H well targeting the middle Bossier shale formation has been drilled and is scheduled to be completed later this year. A third well, the crest C1H is currently drilling and will be completed in December.

Production from our East Texas properties was 19.2 Bcf during the six months, first six months of 2010 compared to 15.6 Bcf during the same period last year. Approximately 2.1 Bcf of our 2010 production was related to the Haynesville and middle Bossier properties that were sold in June. Initial production rates from our James lime wells that were placed on production during the quarter average 7.2 million cubic feet per day and initial production rates from our Pettet oil wells are placed on during the quarter averaged 505 barrels of oil per day, with less than 1 million a day associated gas.

In our conventional Arkoma Basin program, we participated in drilling three wells and production was 10 Bcf for the first six months of 2010 compared to 11.6 Bcf for the first six months of 2009. One of those wells was a Swin operated Johns 2-4H3 well in our Midway field area that was a 2100 foot horizontal well in the Turner Sand. It had initial production rate of 7.2 million cubic foot per day and we have a 60% interest in the well. As reported in the first quarter, we began drilling with one rig in Pennsylvania and have drilled four horizontal wells so far in 2010, all of which are currently scheduled to be completed later in this quarter. We plan to drill about 20 total wells during the year.

In addition, the Greenswig 1H well was placed on production on July 8, and is currently producing 3.3 million cubic foot a day without compression into the pipeline with just over 3000 pounds flowing tubing pressure. The Greenswig well was our first horizontal well and was drilled in late 2008 with a 2945-foot horizontal lateral, and was frackture stimulated with a slickwater frack in seven stages. We are very encouraged by the early results of this well and look forward to our continued progress in the area as the year goes on. We will -- we also believe that Marcellus in northeast Pennsylvania is rapidly developing into one of the best plays in the country. There are still many challenges from regulatory, logistics, and environmental perspectives. We fully expect those to be worked out over time.

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

Good morning. As Steve noted earlier, we had a very good second quarter, fueled by our strong production growth. We reported earnings for the second quarter of $122 million, or $0.35 a share compared to $121 million in the same period in 2009. We also reported discretionary cash flow of over $345 million, up 6% from last year, as our strong production growth more than offset the impact of lower realized gas prices and increased operating costs and expenses. Operating income for our E&P segment was $162.5 million for the second quarter compared to $174.4 million for the same period 2009. The decrease was primarily due to lower realized gas prices, in line with increased operating costs and expenses, which were partially offset by our higher production volumes. We realized an average gas price of $4.27 per Mcf in the second quarter of 2010, down 15% from the prior year period.

Our commodity hedge position increased our average realized gas price by approximately $0.58 per Mcf in the second quarter and we currently have approximately 87 Bcf of our remaining 2010 projected natural gas production hedged through fixed price swaps or collars at a weighted average floor price of $6.26 per Mcf. This represents a little over 40% of our expected production in the third and fourth quarters. During the quarter, we also increased our hedge position in 2011 and added some hedges in 2012. We currently have 92 Bcf of our 2011 forecasted gas production hedged at an average floor price of $5.61 and approximately 80 Bcf of our 2012 forecast of gas production at a floor price of 5.50 per Mcf.

Our lease operating expenses per unit of production were $0.85 per Mcf during the quarter, up from $0.73 last year. The increase was primarily due to higher gathering costs and increased water disposable costs associated with our Fayetteville shale play. Our water volumes, disposal rate increases and the use of more third party disposal facilities all contributed to the increase during the quarter. Our general and administrative expenses per unit of production declined to $0.31 per Mcf in the second quarter, down from $0.34 last year due to the impact of our increased production volumes. Taxes other than income taxes were $0.09 in the quarter compared to $0.08 in the prior year. Our full cost pool amortization rate declined in the quarter, dropping to $1.33 per Mcf equivalent from $1.46 in the prior year, primarily due to lower finding and development costs.

Our total per unit operating costs and expenses including LOE, G&A, taxes, and our full cost pool amortization was $2.58 per Mcf in the second quarter, down from $2.61 in the prior year period. Operating income from our Midstream services segment increased by 57% to over $43 million in the seconds. The increase was primarily due to increased gathering revenues and increase in margin from our gas marketing activities related to our -- both related to our Fayetteville shale play, which were partially offset by increased operating costs and expenses.

At July 30, our Midstream segment was gathering over 1.6 billion cubic feet of natural gas per day through 1367 miles of gathering lines in the Fayetteville shale play compared to approximately 1.1 billion cubic feet per day a year ago. Included in our gathered volumes is approximately 170 million cubic feet per day of third party gas, which has more than doubled since the beginning of the year.

To update you on the Fayetteville express pipeline, they are making very good progress and we're currently expect interim service to NGPL as early as October this year and full service commencing on or about January 1, 2011. Our initial firm capacity on this pipeline will be 400 million cubic feet per day as of January 1, 2011, increasing to 1.2 Bcf a day by November of next year. We invested approximately $1 billion in the first six months of 2010 compared to $959 million in the same period last year. At June 30, we had $506 million borrowed our $1 billion credit facility at an average interest rate of 1.2%, and had total debt outstanding of $1.2 billion. This leaves us with a debt to book capital ratio of 31% and a debt to market capitalization rate of only 9%.

As Steve mentioned, during the second quarter, we closed on the sale of a portion of our East Texas properties and have deposited the net proceeds of approximately $355 million, with a qualified intermediary to facilitate potential Lakton exchange transactions.

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

(Operator Instructions) Our first question is from the line of Dave Kistler with Simmons and Company. Please proceed with your question.

Good morning, guys.

Good morning.

Real quickly, looking at the IP 24-hour 30 and 60-day rates out of the Fayetteville, they upticked nicely in Q2. Can you guys delineate for us what portion of that was due to increases in drilling back in the core versus what portion might be due to just maturing green completions?

Well, there's really another component to that, Dave. When you look at our 30 and 60 days, you got to remember that you're not comparing the same wells all the way through there, so it's really not -- really a second quarter issue on at least a 60-day part of it. But in general, compared to the first quarter, we drilled fewer wells on the north and east part of our section and kind of moved back more towards the middle, and those were on the acreage capture wells. And that's really what drove the increase in the IP portion of it. The drilling in the field, back in the field area, when you look at the IP of those wells quarter over quarter, they look about the same. So it's really just on the acreage capture side.

Now, let me mention on the acreage capture side, the first half of the year, we front end loaded acreage capture and we'll have about two-thirds of the acreage capture that we're going to do this year in the first half. So as you go towards the second half of the year, it will look a little different also. And you didn't quite answer the assets question, but I'll just jump out and say it. As you go towards the second part of the year, third quarter, we're doing a lot of what we were doing in the second quarter. As you get into the fourth quarter, we're going to be moving back to the northeast and north of the lake, and so you'll see us capturing some more acreage in the fourth quarter. So it's going to bounce around these next couple of quarters, but most of what you're seeing on the IP and really 30-day is acreage capture. 60 days is really looking more back well into the second quarter, almost into the first quarter.

Great, thank you. And then just one quick one on costs, looking at the LOE creeping a little higher due to increased costs for water disposal, are there any particular measures or things you can do to start bringing that number back to historical levels?

Well, let me start with we've actually guided higher than our costs, so we're pretty happy about the cost where they're at. There is a little bit of cost creep, and when I say cost creep, I mention the transportation portion of that. Our Midstream contract has a small escalator in it and it's about $0.02 an M and so on a Company basis, we assume to the Company cost hasn't changed. On the MP side, there are $0.02 of that was going to our own Midstream Company. Then on the water handling gathering portion of it, we have a series of wells that we own that we use for injection when we can't reuse the water. Two of those wells this last quarter were giving us some trouble. One, significant issues and the other one, not quite as significant. We're working hard to bring both of those wells back on. If we can get them up and running, then you'll see those costs on the water go down. Right now, I can't tell you that we can do that, though. As I'm looking out towards the future, I wouldn't assume that we can cut much back near term. Certainly if these couple wells we can't get them back, we may have to drill another saltwater disposal well down the road and then you would see the costs go down again.

Great. Thank you, guys, very much.

Thank you. our next question is coming from the line of Brian Singer with Goldman Sachs. Please proceed with your question.

Thanks, good morning.

Good morning.

In the Marcellus, can you talk about the visibility of getting kind of frackk work done and the timing and potential solution as you go forward with your program?

Well, we had a couple things that needed to get done before we could even get to the initial production. We had to get a pipeline put to our initial pad and then we will be drilling 20-plus wells this year. That's from three different pads and towards the end of the year, we'll be in a fourth pad. Sometime during August, we'll have all of those various pads hooked up so we can put wells on production. That was the first thing we needed to do, we've been working on that. We're very close to having that done. Then on the frackks themselves, and lining up frackks, frackking is tough in Pennsylvania. We've got some frackk dates set up that we can get the wells that we have done, or we've completed now drilling. But that is a challenge and you're looking out something well past 60 days towards in some cases 90 days to catch those frackk dates. And we're doing everything we can to pull it up, but that's the way it is that direction.

The other thing that hasn't bothered us much, but could bother us going forward is that they have had a very dry year in northeast Pennsylvania and so water has been limited. Fortunately for us, it started raining here before we've had to start to do some of these frackks going forward. But if it stays dry through the fall, you'll see the entire industry be slowed a little bit down just from the fact that there isn't enough water for all the frackks that the industry wants to do.

Great, thank you for the color. And then secondly, on the Midstream services segments, how are you thinking about the strategic nature of that? And is there a point at which, as you move forward with the Fayetteville, you see the Midstream as a candidate for asset sale, or do you see it as a core, a core piece?

Well, right now, it's core. We've talked about it in the past, that the reason we have the Midstream group is that it strategically let's us get wells on faster, let's us set up our system the way we want, not just for today, but for long-term. And we still have a lot of pipe to lay, to actually get all that done. And to just kind of give you a top side number, last year, we laid 1.4 miles of pipe for every well we put on. This year, it was something like 1.8, 1.9 miles of pipe. So we actually laid a little more pipe this year because we're up in the northeast and pushing down to the south. We've got at least one more year and probably a little bit more than that of just laying in the basic infrastructure so we can get to our major portions of our acreage. And then once we get that back bone in, we can start talking about whether the Midstream is important or not to us. So it's farther out before we start talking about if if we would ever want to get rid of it.

Great, thank you.

Thank you. The next question is coming from the line of David Heikkinen with Tudor Pickering. Please proceed with your question.

Good morning, Steve. Just thinking about the Marcellus rig count you might need to keep a frackk group committed, can you give us a thought around either number of wells or activity level as you look forward?

Well, if you wanted to keep a frackk crew, just a single crew committed to your count full-time, you need to have somewhere between four and five rigs running and that's really Marcellus or Fayetteville, whichever. What we're planning to do, we'll keep one rig running this year and then you'll start seeing us probably scale up, and again, this depends on gas price and cash flow and those things, but just probably start seeing us scale up next year. Ultimately, with the acreage the way we have it today, I think we're going to need five or six rigs running. So down the road, we'll certainly have enough rigs running to continue to have a crew working for us full-time. But for the next 18 to 24 months, that's probably not going to be the case and we'll have to worry about frackk windows. We are trying to use some of the leverage we had in the Fayetteville shale with some of our vendors, and trying to put that under some contracts. Don't know if that will work or not, but we're trying to do whatever we can to make sure we've got the crews on time when we need them.

Okay, and then just on the lifetime exchange, how do the -- any acquisitions fit within your current CapEx budget and thinking about if you don't execute a lifetime kind of exchange, what is the tax implication on the East Texas sale?

Well, David, this is Greg. If we don't have any, anything that qualifies in that bucket between now and the end of the year, which we will have something, some things, if you had nothing, we would have about $45 million of current really alternative minimum tax that we would pay this year. That would be the worst case scenario. But things like acreage positions that we're acquiring in areas clearly qualify and so we'll be able to mitigate that somewhat.

I think the other part of your question was how does acquisitions fit in? Again, we're not in the acquisition business per se. If the right thing would come along that had acreage and maybe had a little bit of production, we might look at that. But that 10/31, the first thing we're looking at putting in there is the leases that we are acquiring between now and the end of the year. You've got 180 days to basically close that 10/31 account. So anything worth doing in any of the areas we got, I can tell you that's going to be in there and that's why Greg says -- we'll see what else happens after that.

I was thinking about acreage positions primarily and back half of the year remaining--?

We're working hard on putting the list together, not only in the back half of the year, but if we thought we were going to pick up something next year, if we could somehow accelerate that. So that's part of the reason for just keeping the capital budget where it's at. If you think about it, we had mentioned before that in selling the properties, that saved us over $50 million in East Texas and what we're doing there. But if we can accelerate some of our acreage acquisition and take advantage of some tax things, we'll do that.

Okay. I'll segue that into any updates on the new ventures program, but -- probably not going to get much, but do you have anything you can illuminate, that would be helpful.

We're still picking up acreage on several different plays. In New Brunswick, we have flown gravity magnetics and we are in the process of going out in the field right now to do surface geochem work. The whole -- all of that is to set us up so we can figure out where to shoot seismic and we're in the process of permitting field tests, where you go out and actually try to pick up a very small piece of seismic to see how easy it is to do the seismic and how you want to design your seismic. We'll be doing that later this year on the field test and hopefully sometime next year start shooting some seismic early in the year. We're on track on the New Brunswick portion of it.

Thanks, guys.

Our next question is from the line of Amir Arif with Stifel Nicolaus. Please proceed with your questions.

Thanks, good morning, guys.

Good morning.

First question on the Marcellus, can you give us a sense of what you're thinking of in terms of laterals and number of frackk stages of the remaining 15 to 20 wells that you're going to be drilling or completing up there this year?

On the four we've drilled, they are all over 4000-foot. And I don't know where we'll ultimately end up. I know some people are pushing over 5000 and towards 6000-foot, but you hold right now on our acreage, holds roughly 640 acres when you drill a well, so they will be in the 4000 to 5000-foot range for a while as we're doing first wells in units. As far as frackk stages, I think as we go to frackk these, you will see us have commensurate stages with what you're seeing other people talk about. So it's going to be 10-plus stages. It won't be the seven we had on the well we have now. So everything we're saying says what the industry generally is doing is basically what we'll do as well.

Steve, just relative to any comments you made about the availability of water, how many of those 20 wells do you think you'll have completed by the end of this year? What are you guys thinking about?

Completed, I would say about half of those is what our target is. It may be 12. It certainly won't be 20.

Okay, and then the second question, just on the, on the cost per well, it creeped up this quarter. Can you just talk a bit about, is that due to the 20 wells that just took longer to drill in the southern portion, or is that ongoing cost pressures which you are seeing to drill into each well?

It is simply that 20 wells. If you compare that to last quarter, we had 9 wells that were greater than 20 days. If you factor out the wells greater than 20 days and the various reasons those were in there and take all wells less than 20 days, last quarter and this quarter were almost identical, both in the number of days and the cost of those wells. So it's just a factor that we were to the southern end of the play with one of our rigs. We were drilling wells that vertical depth of over 6000 feet and then putting 5000-foot laterals in those. It just had a little bit of extra costs.

Sounds good, thanks, guys.

Our next question is from Scott Hanold with RBC Capital Markets. Please go ahead with your question.

Good morning.

Good morning.

Can I ask a more direct question on the like kind exchange. What type of things are you specifically looking at in terms of acres and acquisition? I mean, is there some stuff in the Fayetteville, I know some of the partners up there are looking to potentially sell some of their stuff. Is that something that would interest you all, or are you sort of looking at more of the stuff in your new venture program?

Yes, if you're specifically asking are we going to go to Petrobras data room we're not. What we're putting in there, for instance, in the Fayetteville shale, we do, when we put our units together, there's always a little bit of acreage that you have to put together and if you look at our budget there, I don't know what it is we've got something like $40 million this year in Fayetteville shale, just putting the acreage together to drill the wells we need to for first wells in section, as much as we can of that will be put in there. In Pennsylvania, any of the white area we have around our acreage that's open, even though there may be small blocks, any of that will go in there. And then as I said, anything -- to any extent that we can accelerate some of the new ventures things, which we're trying to figure out if we can, our new ventures will go in there as well.

Okay, good. I appreciate the direct answer on that. It made it pretty clear. And in the Marcellus on that well that was -- I'm sorry if I missed it, did you give what the 24-hour IP rate was on that well?

I did not and I don't know if I've got that right now to tell you the truth.

Okay, that's fine.

And that would have been a 24-hour rate that we gave you. But I assume you're talking about 30-day rate or some other rate.

Well, I think that you said it's currently producing 3.3 million a day.

Well, it's, it's been 3.3 million a day since day one, because it went straight into the 3000 pounds.

Okay.

So it's been between 3 million and 3.3 million a day this entire time.

Okay.

And, again, that 3000 pounds is important. Most companies, when they are giving you rates, maybe a thousand pounds, but certainly it's usually even less than 1000 pounds because you have compression. We'll have compression in a couple weeks and that rate's actually going to go up then.

Okay. I appreciate that. And one last question, on the pace of completions in the Fayetteville, you guys, it looks like set a record at 143 wells. What is the pace of completions going to look like in the back half of the year? What's sort of your backlog at this point relative to what it has been in the past?

Well, if you remember, at the end of the quarter, we were trying to catch up and we put 50 wells on in April, but from here forward and today, we've got a backlog of about 30 wells. We'll have about a 30-well backlog, and we'll be drilling on 120 to 130 wells a quarter. So, you will just kind of see that roll, but I think we're back to what we were, around 30 wells any point in time in backlog.

Got it. Appreciate it, guys. Thanks.

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

Thank you, gentlemen. Good morning, and thank you for taking my questions. We've observed many of your peers chase the oil and liquid-rich stories. Some have been early. Most have been late. We haven't seen Southwestern pursue the same conversion, if you will. My question is why, or does that nonnatural gas potential or diversification line within the maritimes basin or what you may be working on within the new ventures group?

Well, we're not opposed to oil, and to the extent that we had a play that had some kind of liquids with it, we're not opposed to that either. We just want to look for whatever is economic and we haven't -- whenever you think about it, you're always looking out on new plays three to five years and we don't really know how to predict what the price of either product is going to be, so we just look for good plays. I can tell you that some of our new ventures, and you mentioned New Brunswick, New Brunswick could have both an oil and gas window in it, so it certainly could have liquids with it. Some of the other new venture plays we are looking at are oily plays, but it wasn't because we said go look for oily plays. It was just that some would fall into that category. All of them are economic or should be economic under reasonable price scenarios. The only thing that we do differently is if today, if you've got an oil play and a gas play that's in a new ventures group, for instance, and everything's equal on them, you're going to try and get to the oil play faster than the gas play. But that's the most we do as far as strategic. Where you look for the best projects, we're going to make sure we get our PVI that we want to get on those projects and then we'll drill whatever we've got.

Got it, thank you. And one more, if I could. The regulatory pendulum has swung pretty far in one direction in the Marcellus, particularly in the State of Pennsylvania to the point where it's become maybe a bit of an overhang. Do you fear it becomes a hangover, a headache, if you will, and would that ever prompt you to monetize your position where you may recycle those proceeds into the Fayetteville or even the maritimes basin potential?

Well, you said is it going to get to be a headache, I can tell you it's a headache right now from that standpoint. But one of the things we've always said is if, if an area doesn't want us, we don't plan to be there. What we can tell from Pennsylvania is they want the industry ultimately. They have got a lot of things they have to sort out. As long as we believe that they want us, we'll be happy to be there and we'll keep working that direction and go with it. If we come to the conclusion that they don't want us, then we're not going to be there as a Company and we'll figure out a way, whether it's sale or bring in somebody that drills for us or something, where we don't have to operate there.

So right now, we think it is going to get better rather than worse. We think that's going to take some time to do that. That's one of the reasons we're only running one rig, besides just kind of working within our cash flow, but we don't want to jump out there and put a bunch of rigs to work and then have this thing crash around us either. So we're taking it cautious, being flexible with it. We'll watch it. If it gets worse, we'll respond. If it gets better, we'll respond that way as well.

Thank you for your thoughts.

Our next question is from the line of Jack Aydin of KeyBanc Capital Markets. Please proceed with your question.

Hi, Jack.

Of the 120 to 130 wells you're drilling third quarter, how many of those to capture the acreage, to hold the acreage?

For the next couple of quarters, I would say in any quarter, 30 to 40 roughly a quarter.

Okay. Now, looking forward for 2011 how many do you need in order to maintain in a way -- keep your program going?

Depends on what keep your program going means.

Well, a way to -- I know you haven't said the budget for 2011 -- I'm just trying to see what kind of budgets you might be thinking about in 2011 and how many rigs you need, to maintain, to carry that budget?

Let me kind of answer two pieces. As far as the budget for 2011, we are going to build a budget that has minimum borrowings on it, may have a little bit of borrowings, but basically try to stay within cash flow. That will probably be, without looking, not having done the 2000 budget yet it's probably going to be what we've got this year give or take $2 billion. Then when you start talking about Fayetteville shale and exactly and I think you're trying to get to growth rates in Fayetteville shale, if you looked over the last three years, we've roughly drilled the same number of wells the last three years. Two years ago, we had 76% increase in production. 50% -- I think it was 55% or something last year. We're talking about 32% this year. If you just keep that same number of wells per year out there, that number drops in the 26%, 27% range next year and you can see from progression, it just kind of works its way out. About five years from now, you're in the 8% to 10% range, just keeping the same number of rigs running. If that's all we do, that's kind of the program for increasing production each year.

Thank you.

Our next question is from the line of Marshall Carver of Capital One Southcoast, please proceed with your question.

Yes. On the dry weather in northeast PA, are you thinking that it's just going to be more expensive to get water or that you wouldn't be able to frackk wells at all, because you couldn't get permits and things like that?

The way it works at least for us, and different companies, depends on where you're at in Pennsylvania, how you're getting your water but we have permits to take water out of certain streams and rivers in Pennsylvania. With the dry weather, what they did was come in and say, okay, take your permit and cut it by this amount and so they just cut how much you could take out of the various streams. Which we built a couple of holding ponds and the whole concept was is we put water out of the streams, fill the holding ponds and those holding ponds will use the frackk wells and we kind of get ahead of the game. Well, to the extent that you've got holding ponds and you can stay up with the number of permits it doesn't slow you down at all but that's the trick. That's the game you're playing. In our case, we thought we had plenty of water that we wouldn't have to really even worry about the holding ponds and now we're having to make sure we've got the holding ponds filled before we go frackking the wells. I think each Company's going to have a little bit different issue. But in general in -- at least the northeastern portion of Pennsylvania, they significantly restricted each permit and it's just across the board, this stream, everyone's got a permit on this stream, everyone's got a permit on this river, take whatever number you had before and cut it by this percent and that's how much you can take out a day or that's how much you can take out a week.

Okay, that's very helpful. And one follow-up on that, is that just -- how widespread is that? Is that just Susquehanna, or do you know if it's--?

I really don't know. I know that in the Bradford-Susquehanna areas, we're working, it's there, but I really don't know about the weather in the rest of the state or how the various companies are getting their water.

Okay. Thank you very much.

Thank you. Ladies and gentlemen, we have reached the end of our allotted time for questions. I would like to turn the floor back over to Mr. Mueller for closing comments.

Thank you. We're excited and pleased about what's going on. We're -- we've made a lot of progress this quarter and when you think about it, Fayetteville shale continues to perform. We're continuing to learn there. We've still got a lot to learn. We've got our first production in Pennsylvania. We're excited about that. And then when you look at the bigger picture, we just talked about the water, there are other issues out there. And we know we've got a lot of work to do, both on the technical side and then gas price is still a challenge, continues to be volatile. We will take advantage of those hedging opportunities that we've already done in 2010, and done in 2011, 2012. We'll continue to try to find the right places for us to add more hedges so that we can get rid of some of that volatility and we can lock in better what we're doing in the future.

And then when you look at going forward, we've talked about the various areas. We talked a little bit about new ventures, but keep in mind we'll continue to build Fayetteville. We'll use our East Texas and Pennsylvania as jumping points to continue to grow, but also to kind of fill in down the road, two, three years. And then five years down the road we've got our new venture. So we think we're on track on all three areas. Immediate near term, the middle term, and then the longer term. And so we're just excited about what's going on in the quarter. We wish gas price was higher, and with that, I thank you and look forward to a good third quarter.

This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.