[SWN] - Southwestern Energy Company

Q3 2010 Earnings Conference Call

Friday, October 29, 2010

Officers

 Steve Mueller; Southwestern Energy; President and CEO

 Greg Kerley; Southwestern Energy; CFO

 Brad Sylvester; Southwestern Energy; VP, Investor Relations

Analysts

 Scott Hanold; Royal Bank of Canada; Analyst

 Scott Wilmoth; Simmons & Company International; Analyst

 Amir Arif; Stifel Nicolaus; Analyst

 Brian Singer; Goldman Sachs; Analyst

 Rehan Rashid; FBR Capital Markets; Analyst

 Gil Yang; Bank of America Merrill Lynch; Analyst

 Thomas McNamara; Impala Asset Management; Analyst

 David Heikkinen; Tudor, Pickering, Holt & Co.; Analyst

 Nicholas Pope; Dahlman Rose & Co.; Analyst

 Dan McSpirit; BMO Capital Markets; Analyst

 Robert Christensen; Buckingham Research Group; Analyst

 Jack Aydin; KeyBanc; Analyst

Presentation

Operator:  Greetings, and welcome to the Southwestern Energy's Third Quarter Earnings teleconference call.  

At this time, all participants are in a listen-only mode.  A brief question-and-answer session will follow the formal presentation.  If anyone should require operator assistance during the conference, please press star zero on your telephone keypad.  

As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Steve Mueller, President and Chief Executive Officer.  Thank you, Mr. Mueller.  You may begin.

Steve Mueller:  Thank you, and good morning.  Thank you for all of you joining us.  With me today are Greg Kerley, our CFO, and Brad Sylvester, our VP of Investor Relations.

If you've not received a copy of yesterday's press release regarding our third quarter results, you can call 281-618-4847 to have a copy faxed to you.  

Also, I'd like to point out that many of the comments during this teleconference are forward-looking statements.  They involve risks and uncertainties affecting outcomes, many of which are beyond our control, and are discussed in more detail in the Risk Factors and the Forward-Looking Statements sections of our annual and quarterly filings with the Securities and Exchange Commission.  

Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may vary -- may differ materially.

Let me begin.  

We had an excellent third quarter.  Despite lower gas prices, our earnings and cash flow were up significantly compared to last year.  This increase was primarily driven by our production growth of 44% compared to last year and 7% sequentially.

We are also driving down well costs while beginning to better understand the well spacing for the Fayetteville Shale play.  I'll speak more about these points in a few moments.

Now, to talk about each of our operating areas.

During the third quarter, our gross operated productions on the Fayetteville Shale reached over 1.5 Bcf per day, up from approximately 1.2 Bcf per day a year ago and also surpassing the net production mark of 1 Bcf per day.

During the third quarter of 2010, our horizontal wells had an average completed well cost of $2.8 million per well.  That cost matches the lowest quarter we've ever had since beginning drilling horizontally.  

The average horizontal length was 4,503 feet, almost 500 feet longer than the last time we had 2.8 million a day -- $2.8 million per well cost.  And the average days to drill from reentry to reentry was 11 days.

We continue to see faster drilling times, and in the third quarter, we had eight wells placed on production which had average times to drill to total depth of five days or less from reentry to reentry.  

Our horizontal rig count stands at 13 rigs compared to the 15 rigs we averaged during the first nine months of 2010.

The 145 Fayetteville wells placed on production during the third quarter of 2010 averaged initial production rates of nearly 3.3 million cubic foot per day, down 5% compared to the second quarter.  Results for the quarter include 58 wells, or 40%, placed on production, which were the first wells in a new section, and 36 wells, or 25%, drilled to test tighter well spacing.  

We also set a new record during this quarter by placing the play's highest-rated well, the Harlan 9-10 #1-12H, located in Cleburne County, on production with an initial production rate of approximately 8.7 million cubic foot per day.  This well had a completed lateral length of 3,874 feet and a nine-stage fracture stimulation.  After 34 days, it's still producing 5.7 million cubic feet per day.

We continued to test tighter spacing and at September 30, 2010 have placed over 520 wells on production that have well spacing of 700 feet or less, representing approximately 65-acre spacing or less.

Previously, we have stated that based on the wells drilled to date, we'd expected a minimum of 10 to 12 wells per section to effectively drain the reserves, which represent the 65-acre spacing.  

However, early production performance from recent well spacing test indicates there are areas of the field that may be economically developed at tighter spacing.  

At this time, we have confirmed that approximately 20% of the roughly 600,000 net acres drilled to date can be drilled at 30 to 40-acre spacing; approximately 40% can be developed at 65-acre spacing, and the remaining 40% requires additional results to determine if development on tighter spacing than 65 acres is warranted.

We will continue with our well spacing program to better define the areas of field that are suitable for tighter spacing and expect to know more about the well spacing on the remainder of our acreage in 2011.

Switching to East Texas, production from our East Texas properties was 26.9 Bcf during the first nine months of 2010, compared to 24.6 Bcf during the same period last year.

Approximately 2.1 Bcf of our 2010 production was related to the Haynesville and Middle Bossier properties, which were sold in June.  We still have approximately 10,500 net acres with Haynesville and Middle Bossier Shale potential and have drilled three wells on this acreage to date.  The Timberstar Blackstone A-1H, targeting the Haynesville Shale formation, was placed on production in August at an initial production rate of 13.2 million cubic feet per day.  

The other two wells, which are targeting the Middle Bossier, will be completed in the first quarter of 2011.

In our Conventional Arkoma program, production was 14.8 Bcf for the first nine months of 2010 compared to 16.9 Bcf for the first nine months of 2009.  

In Pennsylvania, we have drilled nine horizontal wells, three of which are currently being completed, and we expect results from those wells sometime next month.  Approximately 15 wells are expected to be drilled by year-end, seven of which are expected to be completed by year-end.  

You may remember that in July we placed our first well in Pennsylvania on production, the Greenzweig #1-H, and at our second quarter earnings release date, it was producing approximately 3.3 million cubic feet per day without compression into a pipeline with just over 3,000 pounds of flowing tubing pressure.  

Since that time, we've cleaned out the well bore, and post-cleanout, the well reached a peak rate of over 5 million cubic feet per day in September and is currently producing 2.8 million cubic feet per day with approximately 1,900 pounds of flowing tubing pressure.  

The Greenzweig had 2,945 feet of completed lateral and was fracture stimulated with slickwater in seven stages, so this is very encouraging.  The wells that are currently completing will have average lateral lengths of approximately 4,500 feet and have several more frac stages.

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

Greg Kerley:  Thank you, Steve, and good morning.

As Steve noted earlier, our results for the third quarter were excellent.  Earnings for the quarter were up 36% to $161 million, or $0.46 a share, compared to $118 million, or $0.34 a share, for the same period last year.

We also reported discretionary cash flow of over $421 million, which was up 27% from last year and set a new record for the company.

Operating income for our E&P segment was $217 million for the third quarter, up from $172 million for the same period in 2009, as our strong production growth more than offset the impact of lower realized gas prices and increased operating costs and expenses.

Our average realized gas price fell 8% to $4.67 per Mcf in the third quarter compared to $5.06 for the same period last year.  

We currently have approximately 44 Bcf of our fourth quarter projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $6.26 in Mcf.  This represents approximately 40% of our expected production during the quarter.

Our lease operating expenses per unit of production were $0.85 per Mcfe during the quarter compared to $0.76 last year.  The increase was primarily due to higher gathering and compression costs related to our Fayetteville Shale play.  

Our general and administrative expenses per unit of production declined to $0.28 per Mcfe in the third quarter, down from $0.38 last year due to the impact of our increased production volumes, while our taxes other than income taxes were $0.12 per Mcfe in the quarter compared to $0.10 in the prior year.

Our full cost pool amortization rate continues to decline, dropping to $1.31 per Mcf in the third quarter from $1.43 in the prior year, primarily due to our lower finding and development costs, combined with the sale of certain East Texas oil and gas leases and wells in the second quarter of 2010.

Our total per-unit operating costs and expenses, including our LOE, G&A, taxes, and full cost pool amortization, was $2.56 per Mcfe in the third quarter, down from $2.67 in the prior-year period.

Operating income for our Midstream Services segment more than doubled in the third quarter to $53 million compared to $25 million a year ago.  The increase was primarily due to increased gathering revenues, which were partially offset by increased operating costs and expenses.

We currently forecast operating income for this segment of approximately $180 million for the year and EBITDA of approximately $210 million.

At October 25, our Midstream Services segment was gathering over 1.7 billion cubic feet of natural gas a day through over 1,500 miles of gathering lines in the Fayetteville Shale play.  This compared to approximately 1.3 billion cubic feet a day a year ago, and included in our gathered volumes is approximately 190 million cubic feet per day of third-party gas.

To update you on the construction of the Fayetteville Express Pipeline, we are very happy to report that interim service began earlier this month and primary service will commence on or about December 1.  Our initial firm capacity on the pipeline will be about 400 million cubic feet per day on December 1, 2010, increasing to 1.2 Bcf per day by November of 2011.

We invested approximately $1.5 billion in the first nine months of 2010 compared to $1.4 billion in the same period last year and expect our capital investments for the year to be at or below our original capital budget of $2.1 billion.  

At September 30, we had $617 million borrowed on our $1 billion credit facility at an interest rate of less than 1% and had total debt outstanding of $1.3 billion.  

At the end of the third quarter, our debt to book capital ratio was 31%; however, we expect that to decline to about 28% by year-end.

In summary, we had a great quarter, and in fact, we had one of the best quarters in the company's history.  We're uniquely positioned to weather the current low gas price environment as one of the lowest-cost operators in our industry with one of the strongest balance sheets.

That concludes my comments, so now we'll turn it back to the Operator, who will explain the procedure for asking questions.

Questions and Answers

Operator:  Thank you.  We'll now be conducting a question-and-answer session.  (Operator instructions)

Our first question is coming from the line of Scott Hanold with Royal Bank of Canada.  Please proceed with your question.

Scott Hanold:  Yes, thanks.  Good morning.

Unidentified Company Representative:  Good morning.

Unidentified Company Representative:  Morning.

Scott Hanold:  Steve or Greg, could you talk a little bit about the reduction in the rig count in the Fayetteville from 16 horizontal to 13?  Are you all seeing more efficiency where you could do that and not really need to change your CapEx or production guidance materially?  And what are your thoughts going into 2011?

Steve Mueller:  Well, certainly, reducing the rigs to the 13, we haven't changed our guidance for this year, so we think we can hit all of our numbers with the lower rig count for this year.  

And then as you look at 2011, we haven't put a budget together yet, but we can see that it's going to be tough on the pricing side so dropping the rigs now is starting to prepare us for 2011.  I don't know that I'd count that as being the right number of rigs that we'll run next year, but it's not going to be certainly in the 15, 16 range; it'll be 13 or less.

Scott Hanold:  Okay, so you could actually pull off some more rigs into next year and that wouldn't really -- and that doesn't concern you as far as HBP-ing that?

Steve Mueller:  No, from an HBP standpoint, this year, 2010, we're doing about 230 wells.  Next year, that drops significantly.  It's in the 130 to 150 well range on the high side, and that drops to around 100, a little less than 100 the year after that, and we've pretty much got it all held.

Scott Hanold:  Okay, great.  And then as a follow-up, on the Harlan well -- I think it was the Harlan well, right?

Steve Mueller:  Right.

Scott Hanold:  Was there sort of a new cocktail there, or is it just in a good part of the play?

Steve Mueller:  It wasn't a new cocktail, and we'll figure out if it's a new part of the play.  It was actually one of the wells that was the first well on a section and is in one of the kind of newer areas.  

For those who kind of know our acreage, as you go off, we've been drilling in the far east.  We've been drilling kind of in the middle part of the map, and this is about halfway in between the far east and the middle, where we've just been drilling new wells.  So don't know yet whether it's a good or better part of the play, but we're certainly excited about having it.

Scott Hanold:  Yes, I mean the depth was sort of an average depth well there, is that correct?

Greg Kerley:  Yes.

Steve Mueller:  Yes, it was.  It was on -- as you think about that, the hole we need to fill on in the eastern side of our play, it's on the southern end of that hole.

Scott Hanold:  Right.  Okay, great.  Thanks, guys.

Operator: Your next question is from the line of Scott Wilmoth with Simmons & Company International.

Scott Wilmoth: Hey Steve, just following up with your comment about the 130 to 150 wells needed, the HPP acreage next year and I'm just trying to tie that to the 10-K. It kind of says you guys have maybe 34,000-35,000 acres expiring in 2011. If I just divide that by 640 or so that implies about 50 wells. Where am I off on that?

Steve Mueller: Well, we're not going to just do the ones that are in 2011; we'll get ahead on the other ones. For instance right now we've got rigs in that eastern part of the play kind of filling in that hole; we really don't care if it's 11, 12 or 13, it makes sense to catch as many as you can in that area while you're there.

Scott Wilmoth: Okay, so that 130 to 150 is not for only 2011 expiring--?

Steve Mueller: No. Like I say, by the time we get to somewhere around mid 2012, we'll have all the acreage captured with the exception -- and we talked about this in the past, 156,000 acres of federal, we need to drill 11 wells between now and the end of 2011 basically to hold that acreage and we've already drilled a couple of them this quarter, you'll see us drill about five total this year. And that kind of keeps that 156,000 acres under a different track but it holds all of that.

Scott Wilmoth: Okay and the when I think about 2011 activity can you kind of give us an allocation in terms of  we already knew 130-150 will be going towards holding acreage; how much will be testing downspacing and how much will be kind of interior development mode?

Steve Mueller: We will be slowing down on downspacing. We hope with the patterns we're doing this year we'll have 90% of our answers, but there could be a small part of the field where we have to go back in and do a little bit of testing, but right now I wouldn't expect a lot on the downspacing testing part of it. As I say, we'll have something over 100 wells to do from the standpoint of holding acreage or first wells in section. And then the rest of that we'll actually start going in and drilling pad work to start to do that pad work.

Scott Wilmoth: Great and then just following up on your comment that you could be running 13 or less rigs next year, what rigs do you have currently on contract and when are those expected to roll off, any in the near future? And then what are your thoughts on laying down company owned rigs if prices are low enough?

Steve Mueller: Well, 11 of the 13 big rigs we own, the other two have relatively short-term contracts. I think right now I'd have to go back and make sure, but I think they're working month to month right now. But, we're talking about signing a year contract with those rigs. As far as laying down ours, if the gas price isn't there to support it, we don't have any problems laying down our rigs.

Scott Wilmoth: Okay and last question for me. Can you update us on thoughts or plans for additional hedges in 2011?

Steve Mueller: Well, we'd love to hedge more; we just need the right price.

Operator: Your next question is from the line of Amir Arif with Stifel Nicolaus.

Amir Arif: First question on the IP rates for the wells drilled in this quarter, even if you ignore the five wells, the older wells, just given that the laterals were relatively similar to last quarter, can you just tell us what was causing the IP rates to be down a little bit from last quarter?

Steve Mueller: I can give you a little bit of color and for those who like details; I'm going to hit some numbers here, so get out your pencils. We said that we had 36 wells that were spacing tests; those 36 wells averaged 3148 Mcf a day. We had 58 wells. They were first wells on sections. They averaged 3004 and then we had the other 51 wells or 35% that were basically 600-foot typical 65-acre spacings; those were 3596 or almost 3.6 million cubic foot a day or 3.6 million a day.

And then we talked about in the past how much percent are in the shallower north, which also kind of makes that overall number down a little bit; 24% of the wells this quarter were in the shallow north area part of the field. So what you're seeing is just what we've had in the past. We will have a different mix each quarter. That mix in the quarter is going to have an effect but what's really interesting about these numbers, the downspacing tests are looking very good for the ones we did, because remember, these weren't 40-acres; there's a bunch of stuff at 20-acres that goes into that 3148. And so I'm very excited about the fact we could just average 3.3 for the quarter.

Amir Arif: Just a follow-up. On the first well in every section, generally that should be average pressures but shouldn't that be as good or if not higher rates or is that--?

Steve Mueller: Well, that goes back to the 24% being up in the shallower north. I'll just remind everyone: In that shallow area, you're going to have a little bit shorter laterals there, which means if we average higher for the quarter or average last quarter, there's some other places we're drilling deeper. But they're going to have a little shorter laterals but they certainly are going to have less pressure and that gives you less IPs.

Amir Arif: Then a second question just on the drilling time, 11 days but some wells coming in at five; how long of a time do you need to sort of shift all the wells rolling count towards the five or six or seven days or wherever it's going to average?

Steve Mueller: The days will come down as we do more and more pad drilling. This year we're between 1.5 and 1.8 wells per pad average for the year; next year that will go up above two and then by the time you get to sometime 2012 we'll be doing in the six plus range, so over the next 18 months you're going to see that go up quickly and that will drive those days down. And we're very comfortable because the pad work we've done this year with the downspacing, we've averaged about eight days on the pad, a little less than eight. We're comfortable we can go from the 11 to eight.

And then these five days, if you remember, this is where last year it took us two bit runs on average to drill our wells and these five-day wells is one bit run to do it with some kind of new bit technology. We don't know how much of the field yet that's going to work in and whether we can do it across 80%, 50%, whatever that number, but the extent that we can do a large part of the field at that four to five day range, that eight drives down from there. But that's all going to happen over the next 18 months.

Operator: Your next question is from Brian Singer with Goldman Sachs.

Brian Singer: On the balance sheet, can you talk to what level of additional debt you're willing to take on in 2011 and how aggressively you'd consider assets sales, which I guess would then help us in thinking about how you would respond from a drilling perspective at various gas prices?

Greg Kerley: We are pretty committed, just like we were this year to live within a certain level of cash flow. We had a delta that we were willing to go above in our new ventures area and as we started drilling in the Marcellus but everything else has stayed in the cash flow neutral range. And as we end the year basically with the asset sales that we've had this year, we'll be borrowing just a couple of hundred million dollars for the full balance sheet year. As we go into next year, while our debt to capital will be down to about 28%, we don't quite know obviously what gas prices are going to be next year and we're definitely going to plan a balance sheet and a budget that stays within a cash flow level that we're comfortable being within. That will be pretty close to whatever we believe the cash flow level is going to be.

Steve Mueller: Let me add one thing to that. We haven't got our 2011 budget done by any means and so I don't have exact numbers, but I would expect with what I know today with the gas price that's out there, expect that 2011 is going to have a smaller capital budget than 2010. So we are dedicated to work within the environment we have and build our budget to whatever we can work with and win in that environment. So we're not going to push too much. We may sell some other assets but we're not building a program to sell a bunch of assets so we can invest a bunch of capital and go that direction. That's not the way we're looking at the future.

Brian Singer: And so should we expect then that you still will be comfortable with the same kind of couple of hundred million dollars of additional debt next year as this year or are you thinking ultimately you plan to keep debt flat next year versus this year?

Steve Mueller: We haven't got that far but certainly for us, $100 million to $200 million is basically flat, so that's kind of cutting hairs right now; we'll know more here once we get the budget done.

Brian Singer: Thanks and lastly, how should we think about your activity levels and where you want to take the Bossier drilling and the Marcellus drilling from here?

Steve Mueller: We have to drill some wells just to hold some of our acreage and so we'll do that. When you think about what we're doing -- and we said the first well we've done is a Haynesville well, the next two that we drilled have been Bossier. The Bossier is actually thicker than the Haynesville and in core, because we've cored one of those wells, it looks better and so we need to get some tests on the Bossier itself and then we can make a decision on how fast we want to go. But certainly in the fourth quarter and in the first quarter of next year you're going to see us drill some wells just to hold some acreage.

Operator: Your next question is from Rehan Rashid with FBR Capital Markets.

Rehan Rashid: On the Canadian front, real quick, any update, you've had some time to do some more work geologically speaking at least?

Steve Mueller: To give everyone kind of an update where we're at in Canada, we got that awarded to us where we could actually start doing some work last May. We've gone out and flown gravity and magnetics and are just now getting the data in and starting to do the interpretation. That'll probably be done later this year or going to early 2011.

We also have done what they call surface geochem where they actually go sample the surface. We put samples out there in September and have just finished a week ago getting those all back. You leave them in the ground, you sample for about a month to month and a half. Those are all in. You have to do an analysis on that and then you'll interpret that; that's early next year as well.

The other thing that we've done is we started preparing to shoot 2D seismic on original grid in early 2011 and one of the ways you prepare is you go out there and test various kinds of sources to see what the signal will be and whether you need to use dynamite or vibrators or other kinds of sources and we've done that in two spots in the areas that we thought would probably be the deeper parts of the basins that are there and are getting good reflections, with relatively low loads on a dynamite type source.

And that tells you two things; one, we can get good seismic and secondly, getting good reflections and we're getting good reflections down about 15,000 feet, says that there's some basins out there. And that was one of the key things. So, that's probably the newest news is that we are getting a little bit of reflections on some seismic. But again, those were point sources, just testing to see what the source would look like.

Rehan Rashid: Thank you. One more quick question going back to the five days. I know one kind of bit run helped it down to that level but geologically speaking maybe, what helped?

Steve Mueller: There's really not anything from a geologic standpoint. Certainly if you're in a faulted area or you're in an area that's got a lot of changes in dip, you probably aren't going to be able to do it in five days because you're having to do a little bit more control. But really, these wells we've tried now in several different spots and it's not so much geology related, it's just the fact you didn't have to come out of the hole.

Rehan Rashid: Got it. Last one, on the recovery factor front, whatever work you've done so far, the downspacing results, are we comfortable that we are at 50 percentile recovery factor of gas in play or we're not quite there yet?

Steve Mueller: We are striving to get to that point. I don't know if we're quite there yet, but I know a lot of plays that talk about 30% or 35%; we think we've got evidence of certainly well above 40 and heading towards 50.

Operator: Your next question is from Gil Yang with Bank of America.

Gil Yang: You said that your rate for the Fayetteville, the growth rate was 1.5 Bs per day, I think. Can you tell us what your third quarter exit rate is and what your full-year exit rate is anticipated to be?

Steve Mueller: I really don't have that right now, to tell you the truth. The third quarter exit rate is a little bit above what our average was at year-end. It's easy enough to back-calculate from our guidance but I don't have it sitting right here.

Gil Yang: All right. In terms of the well count obligations for 2011; 130 to 150, how many wells would you have to drill to stay flat at your exit rate for 2011?

Steve Mueller: I don't know.  Again, I don't know about the exit rate, but I can tell you how many it would take right now.  It takes about eight to nine rigs.

Gil Yang: Eight to nine rigs to stay flat from current production rate?

Steve Mueller: Yes, probably.

Gil Yang: Or to stay flat for the year versus 2010?

Steve Mueller: To stay flat for the year at today's rates.  And the reason I say eight to nine, it depends on how fast you want to assume you're going to drill the wells.  But--.

Gil Yang: --Okay.  And then, last question, about the pads.  You said that you're sort of eight days per well per pad--on a pad.  What's the average days per well off the pad?

Steve Mueller: Well, you're looking at it basically with our previous quarter numbers.  Last quarter, it was over 70% of our wells were single wells being drilled and that was about 12 days per well.  So that's kind of your bookends.

Gil Yang: Okay, great.  Thank you.

Operator: Our next question is from the line of Thomas McNamara of Impala Asset Management.  Please proceed with your question.

Thomas McNamara: Good morning, gentlemen.  Just a couple ones.  Steve, could you tell us when you think your mix, so to speak, of the well detail bottoms? You had 24% to the north and shallower and a higher percentage this year of total production?

Steve Mueller: I can give you some general feeling and there's kind of--the near term we're going to continue to fill in that hole that we have in kind of the eastern part of our acreage.  And as you go into the fourth quarter and the first quarter, we're going to be moving up north of the lake some more.  So I would expect the next couple of quarters--and originally we had a plan that was kind of straddled between third and--between fourth and first and it may get a little bit more in fourth than first.  But you'll see us going up in the real shallow north of the lake and kind of filling that in towards the end of this year, early next year.  I think if you look out in the future and say, okay, when you're on pad drilling where will you be drilling at?  We'll really be drilling across the entire play, and then you'll get kind of a constant average.  And the reason we'll be drilling across the entire play is the thing that drives the system is your pipelines.  And if you put all your rigs in one spot, you'll overload on the pipeline system and you'll be backed up from whatever it's doing.  So we'll be moving the rigs around basically to keep the system full and consistent and by that very nature it makes it go across the play.  So we've got probably three quarters of, as I said, drilling this 150 wells next year and filling in the holes and getting those first wells in section, and then you're going to see us start moderating across the area.  And by 2012--mid 2012 when we're doing that pad work, it will get a little lumpier because today, remember, we're drilling less than two wells per pad, so you can put them on fairly consistently - one to two wells at a time.  You'll be drilling eight--six to eight wells, 10 wells per pad.  It will get a little lumpier and it will be spread across the play.

Thomas McNamara: Right.  And just with the 2.8 million average cost per well, could you speak to the variability and some of the reason behind if it's a widespread?

Steve Mueller: Yes.  In general, the shallow part of the play is 2,000 foot or less in depth.  Those wells actually cost 2.5--actually about $2.4 to $2.5 million.  The very southern end of the play today is about $3.5 million and it's about 6,500-foot depth.  And so, you get a little bit of swing on that portion as you go through.  The other thing that you're seeing a $2.8 million number today though is the full effect of the sand and some of the other things we've done from vertical integration.  So that portion of it, if you compare us to say others in the industry who aren't integrated in the Fayetteville Shale, our well is running about $300,000 less than whatever they're doing in the industry.  So I think we've got that moderator in there that helps control our costs going forward, and then we do have the geology that will swing across the area.   Again, as we go shallower you might see that cost a little bit less next quarter or first quarter because we're a little shallower with more of our wells, and then it may go up a little bit once we get that average across the field.

Thomas McNamara: Right.  And just to follow up on that, could you remind us when your framework fracing agreement is due for pricing changes or however we should think about it?

Steve Mueller:  Yes.  Usually right after the first of the year is when we do our next round of bidding for fracing in the Fayetteville Shale.  And to tell you the truth, we're talking to vendors right now.  But our current contract goes through I think it's March 1 of next year.

Thomas McNamara: Okay, great.  Thank you.

Operator: Thank you.  (Operator Instructions.)  Our next question is from the line of David Heikkinen with Tudor, Pickering.  Please state your question, sir.

David Heikkinen: Good morning, guys.  As I think about the play and kind of evolution of the play, one of the questions we get is are you kind of achieving your terminal rate of peak production, lowest cost, and how do things trend over time and what is the continued evolution.  As you think about that across the average two years from now, drilling on a pad, I mean, how should we think about where you think well costs will be, the pace, and all those kind of longer term perspective of where the Fayetteville is going?

Steve Mueller: Well, certainly, if you look at us today, and I'll start with the kind of days to drill, we're averaging 11.  We said that's going to go down to eight.  Certainly, you can't get much faster than five.  That's almost your technical limit.  So we know we're going to have a step jump on there, but then how much can you drive it down from that eight towards six or five?  That's still to be learned over the next two years.  On the pad drilling, we know we can take the days out and that's simply by the fact that rather than having to take the rig apart and move it a mile, and then put it back up every time, you move it 10 feet with everything in the derrick, that's where you're getting the three to four days out of your time.  But we haven't put any factor in for the cost efficiencies when you are able to work on different wells while you're fracing, while you're able to set up different wells.  We haven't put any factor in there for the fact that by this time next year we have all the pads built that we're going to have to build.  And so, our cost in the past had those pads in the cost and in the future it won't have those pads.  The tie-ins on our midstream, again, you'll have lines to every one of those pads by this time next year and you'll see the midstream go down.

So those costs and those cost savings, I can't tell you exactly how much that is, but that's all coming up over the next year as we go through the process.  And then, on the fracing portion of it, most of this year, we've been trying to do test work on spacing.  When you do the test work on spacing, you keep your fracs constant.  You don't have the chance to really play with the fracs and make them better and try to see how much cost you can get out of that.  We started doing that now in some of these other wells that are not part of the testing.  And it looks like just preliminarily that we can cut back on the amount of water we've been using and we're back--we're in about a 10% cutback on our water right now, and it looks like we're getting very similar frac characteristics and very similar EURs and IPs.  And we'll play with that, we'll play with the sand and the sand content.  But if we could take 10% out of the water, that's $50,000 to $70,000 a well.  So those are all--as we get to the pure development mode, there's still those things that are coming up, and that's why we're kind of excited about the next 12 to 18 months, because that's all going to unfold as we go through and make the play even better than it was.  

Your basic big question is how far have you come and where you're at.  We've come a long way.  You think about 2007 - 17 days, 2,100-foot laterals or a little over 2,000-foot laterals, $2 million a day - can we double our production rates in the future and keep the well cost at $3 million?  Probably not.  But we can still go a long way towards making the wells better and more economic.

David Heikkinen: Just on the fracing side and other shale plays we've seen improvements in recovery and production benefits from fracing adjacent wells or kind of doing the zipper frac type design, are those the type of things that you'd also do, I mean, just kind of those little nuances that could potentially improve recoveries?

Steve Mueller: On all of these wells that we're drilling now, where we're doing the test work and we're drilling maybe three wells from a pad or four wells from a pad doing the downspacing test, we are doing zipper fracs on those.  We're trying--we've been gathering data.  I can tell you that with the data we have to date, and we don't have that much obviously, we're not seeing a huge effect.  We're seeing cost effects, but we're not seeing a huge effect on the IP or the EUR, but it's early on that one.  We'll certainly do that.

You certainly have the opportunity to test where you frac them all together and kind of build energy and get more fracing done and we have hardly done any of that to date.  So there will be some of that we can do in the future.  

David Heikkinen: I think that was my two questions.  Thanks, guys.

Operator: Thank you.  Our next question is from the line of Nicholas Pope of Dahlman Rose.  Please proceed with your question.

Nicholas Pope: Good morning.

Greg Kerley: Good morning.

Nicholas Pope: Hey, just looking at the midstream properties, any thoughts there on maybe bringing in a partner to monetize a piece of that or just taking any part of that at some point and spinning any of that out?

Greg Kerley: Well, the midstream we're very focused on that we have a lot of optionality with it.  We have probably--from an operations standpoint we're 18 months, two years away from kind of having the backbone of the system built out, as Steve said, and then really in full development mode.  Really as we look at 2011, it looks like the midstream will be cash--should be or very close to cash flow neutral, and then start becoming cash flow positive after that.  So it is a--it's an asset that we believe is very valuable.  It's an asset that we also look at and believe that our shareholders don't really fully appreciate the value that we have created in that asset.  We'll have about--at the end of this year about 800 million of total capital in all the lines and compression and everything else to date, similar to close to that, 750 to 800.  And an EBITDA that's going to be a little over 200 million and growing with our production stream over the next several years, too, obviously.  So a very valuable asset and it's something that we are looking at and conscious of that right now the multiples in the market for MLP assets, other assets, are higher than what we're trading at.  And we need to figure out exactly how to get the full value of that reflected in our stock.

Nicholas Pope: Yes, appreciate it.  And then, just back to the Fayetteville and downspacing, whenever you talk about the 30, 40-acre spacing, the 20% being you think can be developed, like what do you all--I know you went through it a little bit, but what are the assumptions there in terms of like how much cannibalization you have on like a percentage basis to get to those lower spacing?

Steve Mueller: Yes.  On the 65-acre spacing, we talked about this last quarter, we're between five and 8% interference.  I can tell you that some of the places where the 300-foot spacing would work, which would be basically half that 65 acres, somewhere around 30-acre spacing, that number is approaching 20% interference, but the--it's--they're still very good wells and very economic.  But that's the range, somewhere between eight and 20.

Nicholas Pope: Okay.  That's real helpful.  Thank you.  That's all I had.

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

Dan McSpirit: Gentlemen, good morning, and thank you for taking my questions.  Turning to new ventures, year-to-date investments and new ventures total approximately $111 million.  What will the total budget be for 2010 and what could that look like for 2011?  And then, second to that, if the 2011 strip continues to feel pressure, should we expect funds allocated away from East Texas and to Appalachia and even to Fayetteville Shale with new ventures being the beneficiary?

Steve Mueller: Well, let me answer the second part of that question first.  As you look at 2011 today, East Texas is going to slow down even more than it has.  And again, we--if you think about what we've done this year from original budget, we sold some assets and we've cut about $100 million out of that capital.  And so, what it leaves you with on the kind of development drilling side is Pennsylvania and Fayetteville will obviously be the things that we key on, at least early in next year.  And we'll kind of figure out what the right amount is as we get closer to 2011.  

As far as new ventures goes, we would like--I won't tell you--I can't tell you exactly what our capital budget is going to end up with the year.  If you remember, we have a 1031 exchange from that sale that we did of East Texas and anything we pick up in new ventures, as long as we identify that general area beforehand, we can use to defer some taxes potentially in this 1031 account.  

So if we can accelerate, which we've been trying to do, and get--save some taxes, our number may be another $50 million higher than this number.  I don't know if we can do that or not.  But that's part of the reason you're seeing the new ventures a little higher than we had in the past because we've been trying to do that 1031 exchange.

As we look out in the future, next year -- we have been picking up acreage in some other plays.  We'll talk more about that when we get the plays put together and get ready to do something with them.  But next year I think you'll see us invest at least as much money on land.  As we go forward we'll need some seismic and other sciences like we've done in New Brunswick.  And then you'll see us drill a couple wells next year.  And that will not be in New Brunswick.  New Brunswick's a 2012 drilling program.  

So the -- I don't know the exact number but we'll have some actual well drilling and new ventures and we'll have certainly a significant piece of land as well.

Dan McSpirit:  Okay.  And then one follow-up if I could.  Any estimate on what percentage of the acreage in Fayetteville Shale today doesn't meet your hurdle rate or your present value index at current strip pricing?

Steve Mueller:  Let me answer that a little -- I don't know the exact answer there.  But I can tell you that we've tested about 75% of our acreage to date.  And the current -- with the current strip almost all of that looks pretty good.  But there's about 25% of the acreage we haven't even put a well bore in yet, and a large piece of that's up in the unit that we have, the federal unit we've got, and there's some other acreage off to the west that we haven't done anything with.  And we've done very little with our conventional as well.  So we need to get some more tests in there to even figure out if its economic at all at any price, so.

Dan McSpirit:  Okay.  Thank you.  I'll get back in line.  Thank you.

Operator:  Our next question is from the line of Robert Christensen of Buckingham Research Group.  Please proceed with your question.

Robert Christensen:  Yes.  I'd like to know why you didn't hedge more.  Curious.

Steve Mueller:  Because we've been trying to get $5 hedges and you couldn't.

Robert Christensen:  All right.  But your program works at sub-$5 gas?

Steve Mueller:  Yes, it does.  Yes, it does.

Robert Christensen:  Okay.  So moving on.  Marcellus Shale, when are we going to see or when do you need to make a decision to go a little more active there?

Steve Mueller:  Marcellus is, in our minds, kind of a swing area right now.  We need to do what we need to do at the Fayetteville Shale and then as it -- we had in a previous call, we've got certain things that we want to do in new ventures.  And then the Marcellus is what can you do after you've done those two things.  And with the low gas price, next year I would expect that we're going to have more drilling than this year.  We'll probably exit the year with at least a second rig.  But ultimately we're going to have to have about five rigs running, and that really is driven on gas price.  And we're working on those numbers right now and we'll just see what happens as we put 2011 budget together and what we think about 2011-2012.

Robert Christensen:  But is there sort of a break point on the Marcellus just following on with that?  I mean, is there a -- some time frame where you won't get it all done on your leasehold?  Is there some sort of decision hurdle of -- related to leasing and how fast you can drill the hole at all?  I mean, is there --

Steve Mueller:  Well, we certainly have some lease dates coming up.  Probably the critical year for leasing is towards the end of 2012.  

Robert Christensen:  Okay.

Steve Mueller:  So we've got some time to worry about that.  But that's -- there is that.  And running one rig -- and that's what I said, we have to exit next year with two rigs running.  That gets us a long way towards holding all that acreage we need to hold.

Robert Christensen:  Thank you.

Operator:  Our next question is from Jack Aydin from KeyBanc.  Please proceed with your question.  

Jack Aydin:  Hi, Steve.

Steve Mueller:  How's it going?

Jack Aydin:  Good.  Most of my questions were answered.  But is it fair to think this way?  I know you mentioned about drilling days and all that.  Is it fair to say that you need north of 500 wells in 2011 to hold your production flat and incremental is more or less is going to be growth?  

Steve Mueller:  No, that's-- if you're running -- I said before running eight to nine rigs, that's somewhere around 400 wells, a little less than 400 wells.  Those are production flat.  And we will drill roughly this year, 2010, 500 wells operated and there will be another, oh, I don't know, 100 wells, outside operated.  Those outside operated wells are 25% working interest.  So what really drives your production growth is that wells we operate and -- so that's really, when I'm saying 400 and 500, those are the kind of numbers.  You drill 500 wells next year, you'll have significant growth.  

Jack Aydin:  Okay.  Thanks a lot.

Operator:  Our next question is a follow-up from the line of Dan McSpirit with BMO Capital Markets.  Please state your questions.

Dan McSpirit:  Gentlemen, one more if I could.  Does it make sense once you enter a positive free cash flow state in the Fayetteville Shale or when development is more mature to move the assets into maybe a different corporate vehicle like a partnership that better supports distributions?

Steve Mueller:  We've talked about that.  I don't -- I don't know because we're not quite there yet.  But that kind of goes hand-in-hand when you talk about the midstream.  Part of midstream -- the right time for midstream is when you start to see a decrease in capital and you've kind of built out the system and so that you can actually do these other vehicles.  And to the extent that you could drill a portion of the Fayetteville and get it almost all into a PDP status, there might be some vehicle you want to put it into.  

The reason I say kind of talk about that jointly is, I was talking about before the fact that you're going to have to drill across the entire field, otherwise you overload your midstream system, so that they kind of go tandem.  But to the extent that you could do it in the midstream and you start seeing a similar decrease in midstream, you might be able to do something like that on the E&P assets as well.

Dan McSpirit:  Very good.  Thank you again.

Steve Mueller:  Thank you.

Operator:  Thank you.  Our next question is a follow-up from Scott Wilmoth of Simmons and Company.  Please proceed with your question.

Scott Wilmoth:  Hey, guys.  Just following along with that last question.  Can you give us an update on potential long-term contracts with utilities and what the outlook is for that?

Steve Mueller:  To give everyone kind of a history and -- we've been working for the last, well over a year, with the utilities and working with them on what a contract would look like and whether they'd want a contract and how long that contract would be.  A year ago this time, all the questions had to do with how are you going to take volatility out in any kind of contract you have and is there really enough gas there.  

Today we're past all that and we're talking to several different utilities and various organizations about here's the actual form of a contract that we could use and would this work with your Public Utility Commission.  And then if it would work with your Public Utility Commission, let's figure out how to go towards that Public Utility Commission and get their approval.  

So we've made that much progress to date.  You still have a three corner deal.  You've got the utility.  You've got the E&P business that's supplying the gas.  And then you have to have the Public Utility Commission agree to all that.  And so I think it's -- I think in 2011, you're going to see some movement on that.  But it's not fast movement along the way just because of that.  But we are making progress.

Scott Wilmoth:  Can you give us any details in terms of what current negotiations are or the utilities in terms of time horizon, contract length?  Are we talking three to five or five to 10?  And then how they think about how to -- are you guys looking at collared prices?  Or how are they indexing those prices?

Steve Mueller:  Yes.  Probably the best way to answer that is each utility and each area of the country's a little bit different.  I think ultimately you're going to have more what I'll call index prices range -- range of prices that somehow switch with the commodity.  But that's not necessarily the case everywhere.  

The length of contract, there are some utilities that want very short contracts.  And when I say short, five-year, three-year type contracts.  There are some that want something longer than 10-year.  All the ones we've been talking about that have been longer than 10 years have had some kind of outs on them besides just being some kind of index price as well.  

But again, it depends on the part of the country, the utility commission, their rules, and then the way that the utility's going to supply their gas.  So there's not a standard one out there.  But I will say it ranges from three years to 20.  And there are some that want a locked, fixed price and there are some that want an index price.

Scott Wilmoth:  Okay.  Thanks, guys.  That's all I had.

Steve Mueller:  Yes.

Operator:  Thank you.  We have reached the end of our allotted time for question-and-answer session.  I would now like to turn the floor back over to management for closing comments.  

Steve Mueller:  Thank you.  As you can tell, I'm excited about what we've done this quarter.  This is very challenging times.  It's challenging in a lot of different ways.  And we had a great quarter in these challenging times.  And I think there's going to be some challenging times in the future.  But I think we can have a lot more great quarters as a company.  

And when you think about why that would be the case, we're already, as Greg said earlier, one of the lowest cost operators that are out there.  And you hear a lot of operators talk about, well, tough times, we're going to watch our costs.  Well, we're not watching our costs.  We're trying to drive our costs out.  And that's what we've done by vertically integrating.  That's what we're doing by decreasing the well days.  And then you kind of say, well, there are other challenges out there, that we are in what are very difficult regulatory times almost everywhere in the country.  And sometimes they almost become stifling.  

But again, we're dedicated.  We're going to do the right things as a company.  And we watch as various states look at transparency and we welcome transparency.  And especially if you followed Arkansas, they've got some pending regulations where they want to have complete transparency on fracture of stimulation fluids, and we look forward to that.  I think by the beginning of the year that will be in place and we're excited about that.  And we hope those kinds of things happen in all the states.  

And then when you look at our learning, we've got challenging times.  But with our testing program that we've done and downspacing, we've learned a lot in the Fayetteville Shale.  It's going to set us up over the next couple years.  We're going to be able to get to that pad drilling and be able to drive more cost out of the system.  But the other thing it's done for us, it's setting us up to better do Pennsylvania.  And one of the comments we had, earlier question was, well, why aren't you going faster?  One of the reasons we're not going faster are some of the regulations.  Another reason is we can take the learnings in the Fayetteville and quickly apply them in Pennsylvania.  And we want to do that.  

And those same learnings are going to be applied to our new ventures, too.  And part of what we're doing in new ventures and the kind of projects we're looking for is based on our learnings there.  So that's important.  And whether it's challenging times or not, that's something that we just want to do as a company and is important I think for our success in any price environment.  

And then the last thing -- we talked about this too -- is that when you look at our company, we set ourselves up to manage for low price, high price.  We are going to keep a balance sheet that is clean.  We are going to manage within the price environments there.  You're not going to see us say, well, yes, I know it's $4 gas, but we're going to go borrow a bunch of money and drill into that environment.  On the other side of it you're going to see us drill economic wells.  And as long as we can drill economic wells, we'll drill those economic wells.

So as you look towards the future, we are dedicated to give our shareholders value no matter what the system has out there that they're going to throw at us.

And with that, I'd like to thank you for listening to us this conference call.  And I look forward to reporting more about this in the next quarters ahead.  Thank you.

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

Explanation and Reconciliation of Non-GAAP Financial Measures

We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information with additional meaningful comparisons between current results and the results of our peers and of prior periods.  

One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

See the reconciliation below of GAAP financial measures to non-GAAP financial measures for the three months ended September 30, 2010 and September 30, 2009. Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.

	3 Months Ended Sept. 30,
	2010	2009
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 406,009	$ 315,795
Add back (deduct):
Change in operating assets and liabilities	15,051	15,978
Net cash provided by operating activities before changes   in operating assets and liabilities	$ 421,060	$ 331,773