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Executives

Steven Mueller - Chief Executive Officer, President and Director

Greg Kerley - Chief Financial Officer, Executive Vice President and Director

Analysts

Brian Singer - Goldman Sachs Group Inc.

Dan McSpirit - BMO Capital Markets U.S.

Jack Aydin - KeyBanc Capital Markets Inc.

Gil Yang - BofA Merrill Lynch

Amir Arif - Stifel, Nicolaus & Co., Inc.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

Scott Wilmoth - Simmons

Scott Hanold - RBC Capital Markets Corporation

Robert Christensen - Buckingham Research Group

Rehan Rashid - FBR Capital Markets & Co.

Nicholas Pope - Dahlman Rose & Company, LLC

Southwestern Energ (SWN) Q3 2010 Earnings Call October 29, 2010 10:00 AM ET

Operator

Greetings , and welcome to the Southwestern Energy Co. Third Quarter Earnings Teleconference Call. [Operator Instructions] It is now my pleasure to introduce your host, Steve Mueller, President and Chief Executive Officer. Thank you, Mr. Mueller, you may begin.

Steven 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 have 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 that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail on the risk factors and the forward-looking statement 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 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 the 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 operating 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, with 4,503 feet, almost 500 feet longer than the last time we had $2.8 million per well cost, and the average days to drill from re-entry to re-entry 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 re-entry to re-entry. Our horizontal rig counts 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 the 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 rate well, the Harlan 09-10 #1-12H located in Cleburne County, on production with 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 foot per day.

We continue 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 from the wells drilled to date, we'd expect in a minimum of 10 to 12 per section to effectively drain the reserves which will represent the 65-acre spacing. However, early production performance from recent well spacing tests indicates that there are areas of field that may be economically developed at tighter spacing. At this time, we've 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 the 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 on August and initial production rate of 13.2 million cubic foot 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 some time 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 foot per day without compression into a pipeline with just over 3,000 pounds of flowing tubing pressure. Since that time we cleaned out the wellbore and post cleanup, the well reached a peak rate of over 5 million cubic foot per day in September. And it's currently producing 2.8 million cubic foot per day, with approximately 1,900 pounds of flowing tubing pressure. The Greenzweig had 2,945-foot of completed lateral and was fractured 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-foot 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 in Mcf in the third quarter compared to $5.06 for the same period last year. We currently have a 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 an Mcf. This represents approximately 40% of our expected production during the quarter. Our lease operating expenses for 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 at $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 from the prior year. Our full cost pool amortization rate continues to decline dropping to $1.31 per Mcfe in the third quarter from $1.43 in the prior year primarily due to our lower funding and development costs combined with the sale of certain East Texas oil and gas leases and wells in the second quarter 2010. Our total per unit operating costs and expenses, including our LOE, G&A, taxes and full cost pool amortization, was $2.56 per Mcf in the 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 for 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 2011.

We invested approximately $1.5 billion in the first nine months of 2010 compared to $1.4 billion in the second 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. And now we'll turn back to the operator, who will explain the procedure for asking questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is coming from the line of Scott Hanold with Royal Bank of Canada.

Scott Hanold - RBC Capital Markets Corporation

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?

Steven Mueller

Well, certainly, reducing the rigs to 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 if I'd count that as meeting the right number of rigs we will run next year, but it's not going to be in certainly 15, 16 range. It would be 13 or less.

Scott Hanold - RBC Capital Markets Corporation

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

Steven 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 a year after that. We pretty much got it all held.

Scott Hanold - RBC Capital Markets Corporation

On the Harlan well, I think it was the Harlan well, right? Was there sort of a new cocktail there or is it just in a good part of the play?

Steven Mueller

No, it wasn't a new cocktail, and we'll figure out if it's in the new part of the play. It was actually one of the wells that was a first well on a section. And it's one of kind of the newer areas for those doing kind of newer 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. We 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 - RBC Capital Markets Corporation

The depth is sort of an average depth well there, is that correct?

Steven Mueller

Yes, it was. 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.

Operator

Our next question is from the line of Scott Wilmoth with Simmons & Company.

Scott Wilmoth - Simmons

Steve, just following up with your comment about the 130 to 150 wells needed for HBP acreage next year. And I'm just trying to tie that to the 10-K, 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?

Steven Mueller

Well, we're not going to just give the ones that are in 2011. We'll get ahead on the other ones. If you got a rig in there, you us 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 - Simmons

Okay, so that 130, 150 is not for only 2011 expiring?

Steven Mueller

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 acreage 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 on a different track, but it holds all of that.

Scott Wilmoth - Simmons

And when I think about 2011 activity, can you kind of give us on an allocation in terms of, we already knew 130, 150 will be going towards holding acreage. How much will be testing down spacing? And how much will be kind of interior development mode?

Steven Mueller

We will be slowing down the downspacing. We hope with the patterns we're doing this year, we'll have 90% of our answers. There could be a small part of the field 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 welding section. And then, the rest of that will actually start going in and drilling pad work and start to do pad work.

Scott Wilmoth - Simmons

Following up on your comments 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?

Steven Mueller

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

Scott Wilmoth - Simmons

Can you update us on thoughts or plans for additional hedges in 2011?

Steven Mueller

Well, we'd love to hedge more. We just need the right price.

Operator

Our next question is from the line of Amir Arif with Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc.

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?

Steven 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 we're spacing test. Those 36 wells average 3,140 Mcf a day, 3,148 Mcf actually. We had 58 wells that were first wells in sections. They average 3,040 Mcf, and then we had the other 51 wells or 35% that were the basically 600-foot typical 65-acre spacing. Those were 3,596 Mcf or almost 3.6 million cubic foot a day. And then we've talked about in the past how much percent are we shallow into the 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 make 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. It goes into that 3,148 Mcf. And so I'm very excited about the fact we could just average 3.3 for the quarter.

Amir Arif - Stifel, Nicolaus & Co., Inc.

Follow up on the first well in every section. I mean generally, that should be pressures. But shouldn't that be as good or higher rates or is that...

Steven Mueller

24% being up in the shallow in North. And just remind everyone, that shallow area, you're going to have a little bit shorter laterals there, which means if we averaged higher for the quarter, our 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 - Stifel, Nicolaus & Co., Inc.

And then second question just on the drilling time, 11 days but some wells coming in at five. How long is the time do you need to sort of shift all the wells drilling cap towards the five or six or seven days or wherever it's going to average?

Steven Mueller

The days will come down as we do more and more pad drilling. This year, we're 21.5 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 2012, some time 2012, we'll be doing in a six-plus range. So over the next 18 months, you're going to see that go up quickly and now drive those days down. And we're very comfortable because the pad work we've done this year with the downspacing, we've averaged at 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 to 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 to 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 a eight drives from there. But that's all going to happen over the next 18 months.

Operator

Our next question is from the line of Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

On the balance sheet, can you talk to what level of additional debt you're willing take on in 2011? And how aggressively you'd consider asset 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

Yes, I'll start, Brian. This is Greg Kerley. I mean, 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, 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 hundred million dollars from the full balance sheet year. As we go into next year, while our debt to cap 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 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.

Steven 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 was what I know today with the gas prices 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 within 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 - Goldman Sachs Group Inc.

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

Steven Mueller

We haven't got that far. But certainly for us, it could go, $100 million to $200 million is basically flat. That's kind of cutting hairs right now. We'll know more here once we get the budget done.

Brian Singer - Goldman Sachs Group Inc.

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?

Steven Mueller

I think 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 the Haynesville well, the next two that we've drilled have been Bossier. The Bossier is actually thicker than the Haynesville. And 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

Our next question comes from the line of Rehan Rashid with FBR Capital Markets.

Rehan Rashid - FBR Capital Markets & Co.

On the Canadian front, real quick. Any updates, you've had some time to do some more work, geologically speaking at least?

Steven Mueller

To give a comment out there, we're right in Canada. We got that awarded to us where we could actually started on 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's probably to be done later this year, going to early 2011. We also have done, what I call, surface geochem. We actually go sample the surface. We've put that samples out there in September and had just finished a week ago, getting those all back. You even the ground, you sample for about a month to a month and a half. Those are all in. You have to do 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've started preparing to shoot 2D seismic on a regional 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 we're getting good reflections with relatively low loads on a dynamite-type source. And tells us two things. One, we can good seismic. And secondly, getting good reflections, and we're getting reflection down about 15,000 feet. So that there's some basins out there, and that was one of the key things. So that's the probably the newest news, 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 - FBR Capital Markets & Co.

Going back to the five days. I know, one, kind of a bit run helped it down to that level. But geologically speaking maybe, what helped?

Steven Mueller

There's really nothing 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 depth, you probably aren't going to able to do it in five days because you haven't built a little more control. But really, these wells we've tried now in several different spots, and it's not so much geology related, just the fact you didn't have to come out of the hole.

Rehan Rashid - FBR Capital Markets & Co.

On the recovery frac-ing front, whatever work you've done so far the downspacing results, are we comfortable that we are at 50% type recovery frac of gas in place or we're not quite there yet?

Steven 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 play to talk about 30%, 35%. We think we got evidence of certainly well above 40% and heading towards 50%.

Operator

Our next question is from the line of Gil Yang of Bank of America.

Gil Yang - BofA Merrill Lynch

You said that your rate for the Fayetteville with gross rate was 1.5 Bcf per day, I think. Can you tell us what your sort of core exit rate is? And what your full year exit rate is anticipated to be?

Steven 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 year end. It's easy not to back calculate from our guidance, but I don't have it now right here.

Gil Yang - BofA Merrill Lynch

In terms of the drill and the well count obligation for 2011, 130 to 150, how many wells would you have to drill to stay flat at your exit rate for 2011?

Steven Mueller

Again, I don't know about exit rate, but I can tell you how many to take to be right now. It takes about eight to nine rigs.

Gil Yang - BofA Merrill Lynch

Eight to nine rigs to stay flat from current production rates?

Steven Mueller

Yes, roughly.

Gil Yang - BofA Merrill Lynch

Or to stay flat after the year versus 2010?

Steven Mueller

Just stay flat for the year at today's rates. And there is and I say eight to nine, it depends on how fast you want to see me going to drill the wells.

Gil Yang - BofA Merrill Lynch

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?

Steven 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. That's kind of your bookings.

Operator

Our next question is from the line of Thomas Buckmeier [ph] of Imperial Asset Management.

Unidentified Analyst

Steve, could you tell us when you think your mix so to speak of the well detail bottoms 24% to the north and shallower and higher percentage this year of production?

Steven Mueller

I can give you some general feeling and there's kind of near term, we're going to continue to fill in that hole that we have kind of the eastern Farnborough acreage. And as you go into the fourth quarter and first quarter, we're going to be moving up north of the lake some more. So I'd expect the next couple of quarters. And originally, we had a plan. It was kind of between fourth and first. It may get a little bit more in fourth and first, but you'll see it's going up in the real shallow north of the lake. And it's kind of filling that in towards the end of this year, early next year. I think if you look 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 own 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, in very nature, 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 oils on sections. And then you're going to see it start moderating across the area. And by 2012, when we're doing that pad work, it'll get a little lumpier because today, you'll 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, given your eight, six to eight wells, 10 wells per pad. It'll get a little lumpier. It'll be spread across the play.

Unidentified Analyst

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 wide spread?

Steven Mueller

In general, the shallow part of the play is 2,000 foot or less in depth. Those wells actually costs $2.5 million actually about $2.4 million, $2.5 million. The very southern end of the play today is about $3.5 million, and it's about 5,500-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 at $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 rift, if you compare us to say others in the industry, if we aren't integrated in the Fayetteville Shale, our wells are running about $300,000 less than whatever they're doing in the industry. I think we've got that moderator in there. It 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 it costs a little bit less next quarter or first quarter because really shallower is more of our wells and then it may go up a little bit once you get to that average cross field.

Unidentified Analyst

Could you remind us when your framework frac-ing agreement is due for pricing changes or however we should think about it?

Steven Mueller

Usually, right after the first years when we do our next round of bidding for frac-ing 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 next year.

Operator

[Operator Instructions] Our next question is from the line of David Heikkinnen with Tudor, Pickering.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

As I think about the play and kind of the evolution of the play, one of the questions we get is how you're achieving your terminal rate of peak production and lowest costs and how do things trend overtime and what is the continued evolution? As you think about that across the average two years from now drilling on the pad, 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?

Steven 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 in there, but then how much can you drive it down from that eight towards six or five. That's still what we'd learned over the next two years. On the pad drilling, we know we can take the days out and that simply by the fact that we're having to take the rig apart and move them a mile and put it back up every time you move a 10 feet with everything 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 frac-ing, while you're able to set up different wells. We haven't put any factor 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 effect had those pads in them. The costs in the future won't have those pads. The time is on our midstream. Again, you'll have lines to everyone 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 years as we to go through the process. And then on the frac-ing portion of it, most of this year, we've been trying to do a test work on spacing. When you do the test work in spacing, you keep your fries constant. You don't have the chance to really play with the fries and make them better and try to see how much costs you can get out of it. 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 in the amount of water we've been using, and we're in about a 10% cut back 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 out. 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 along 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 to keep the well cost to $3 million, probably not. We're still a long way towards making the wells better and more economic.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

Just on the frac-ing side and other shale plays, we've seen improvements in recovery and production benefits from frac-ing 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 could improve recoveries?

Steven Mueller

On all of these wells that we're drilling now, where we're doing the test work on drilling maybe three wells from the pad or 4 wells from the pad doing the downspacing test, we are doing zipper fracs on those. We've been gathering data. I can tell you that with the data we have today, and we don't have that much obviously, we're not seeing any huge effect. We're seeing costs effects, we're not seeing a huge effects on the IP. 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 frac-ing done, and we have hardly done any of that to date. So there will be some of that we can do in the future.

Operator

Our next question is from the line of Nicholas Pope of Dahlman Rose.

Nicholas Pope - Dahlman Rose & Company, LLC

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 spin in any of that out?

Greg Kerley

Well, the midstream, we're very focused on, but 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 midstream should be or very close to cash flow neutral and then start becoming cash flow positive after that. So 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 or close to that $750 million to $800 million. And 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. But right now the multiples in 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 - Dahlman Rose & Company, LLC

And then back to the Fayetteville and downspacing, whenever you talk about the 30-, 40-acre spacing, the 20% being you think it can be developed. 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?

Steven Mueller

On the 65-acre spacing, we talked about this last quarter, we're between 5% and 8% interference. I can tell you that some of the places where the 300-foot spacing would work, which would be basically half of that 65-acre, somewhere around 30-acre spacing. That number is approaching 20% interference. But they're still very good wells and very economic. But that's the range, somewhere between 8% and 20%.

Operator

Our next question is from the line of Dan McSpirit of BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

Turning to new ventures, year-to-date investments in 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 Appalachia and even the Fayetteville Shale with new ventures being the beneficiary?

Steven Mueller

Let me answer the second part of the question first. As you look at 2011 today, East Texas is going to slow down even more than it has. And again, if you think about what we've done this year from original budgets, we've sold some assets and we've cut about $100 million out of that capital. And so it leaves you with on a kind of development drilling side, is Pennsylvania and Fayetteville will obviously be the things what we key on, at least early 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 can't tell you exactly what our capital budget is going to end up at the year. If you remember, we have a 1031 exchange from that sale that we did with East Texas and anything we pick up in new ventures, as long as we identified 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 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 reasons you're seeing the new ventures a little higher than we have in the past because we've trying to do that 1031 exchange. As we look in the future, next year, we haven't picked 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 of wells this year. And that will not be in New Brunswick. New Brunswick's a 2012 drilling program. So I don't know the exact number, but we'll have some actual well drilling in new ventures and we'll have certainly some of that new piece of land as well.

Dan McSpirit - BMO Capital Markets U.S.

Any estimate on what percentage of the acreage in the Fayetteville Shale today doesn't meet your hurdle rate or your present value index at current strip pricing?

Steven Mueller

Let me answer that a little bit. I don't know the exact answer there. But I can tell you that we've tested about 75% of our acreage to date. 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 wellbore in yet. A large piece of that unit that we have, the federal unit we've got and there are some 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 until you can figure out if it's the economic at all at any price.

Operator

Our next question is from the line of Robert Christensen with Buckingham Research group.

Robert Christensen - Buckingham Research Group

I'd like to know why you didn't hedge more?

Steven Mueller

Because we've been trying to get $5 hedges, and we couldn't.

Robert Christensen - Buckingham Research Group

But your program works?

Steven Mueller

Yes, it does.

Robert Christensen - Buckingham Research Group

Marcellus Shale, when are we going to see or when do you need to make a decision to go a little bit more active there?

Steven 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 we have in previous call, we 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 a low gas price, next year, I would expect that we're going to have more drilling this year. We'll probably exit the year with at least a second rig. But ultimately, we're going to have about five rigs running. And that really is driven on gas price. So we're working on those numbers right now, and we'll just see what happens as we put 2011 budgets together and what we think about 2011 and 2012.

Robert Christensen - Buckingham Research Group

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

Steven Mueller

Well, we certainly have some lease dates coming up prior to the critical year for leasing is towards the end of 2012. So we've got some time to worry about that. But there is that and running one rig actually That's why I said we have to exit next year with two rigs running. That gives us a long way towards holding all that acreage that we need to hold.

Operator

Our next question is from Jack Aydin of KeyBanc.

Jack Aydin - KeyBanc Capital Markets Inc.

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 the incremental is, more or less, is going to be growth?

Steven Mueller

No. If you're running, I said before running at eight to nine rigs, that's somewhere around 400 wells, a little less than 400 wells to hold your production flat. And we will drill roughly this year, 2010, 500 wells operated and that will be another 100 wells outside operated. Those outside-operated wells are 25% working interest. So it really drives your production drills is that wells we operate. And so that's really what I'm saying, 400, 500, those are the kind of numbers. You drill 500 wells next year, you'll have significant growth.

Operator

Our next question is a follow-up from the line of Dan McSpirit, BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

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?

Steven Mueller

We talked about that. I don't know because we're not quite there yet, but that goes hand-in-hand when we talk about the midstream. Part of the midstream, the right time for midstream is when you start to see a decrease in capital and you kind of buildup the system and so that you can actually do these other vehicles. And to the extent that you could drill a portion of Fayetteville and get it almost on to the PDP status, there might be some vehicle you want to put it into. So you kind of talk about that jointly is as I was talking about before is the fact that you're going to have to drill across the entire field. Otherwise, you'll overload your metering system. So that they kind of go tandem. But the extent that you could do it in the midstream and you start seeing the sand decrease in the midstream, you might be able to do something like that on the E&P assets as well.

Operator

Our next question is a follow-up from Scott Wilmoth of Simmons & Company.

Scott Wilmoth - Simmons

Can you give us an update on potential long-term contracts with utilities and what the outlook is for that?

Steven Mueller

To give everyone kind of a history, 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 want a contract and how long that contract would be, a year ago this time, all the questions had to do with how you're 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 in various organizations about, here's the actual form of a contract that we could use and will this work with your Public Utility Commission. And then if it'll work with your Public Utility Commission, let's figure out how to go towards the 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 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 - Simmons

Can you give us any details in terms of what current negotiations are or the utilities in terms of time horizons, contract link, are we talking three to five or five to 10? And then how would I think about how to -- are you guys looking at collar prices or how are they indexing those prices?

Steven Mueller

Probably the best way to answer that is each utility in each area of the country is a little bit different. I think ultimately, you're going to have more collar 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 I say short, five-year, three-year type of contracts. There are some that want something longer than 10-year. All the ones that we've been taking about them in 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, the rules. And then the way that the utilities is 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 indexed price.

Operator

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.

Steven Mueller

Thank you. As you can tell, I'm excited about what we've done this quarter. This is very challenging times, it's challenges 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 who are out there. And you hear a lot of operators talk about well test 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 there are other challenges out there. We are in a very difficult regulatory times, almost everywhere in the country, and sometimes it almost becomes 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 a complete transparency in fractures, 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 of the states.

And then when you look at our learning, we've got challenging times. But with our testing program that we've done at downspacing, we've learned a lot in the Fayetteville Shale. It's going to set us up over the next couple of years. We're going to be able to get that pad drilling, and we'll be able to drive more costs out of the system. But the other thing it's done for us, it set us up to better do Pennsylvania. And one of the comments we had, earlier question was, why aren't you going faster? One of the reasons we're not going faster is some of the regulations. Another reason is we can take the learns into Fayetteville and quickly apply them in Pennsylvania, and we want to do that. And that same learnings, we're going to apply to our new ventures too. And part of what we're doing in new ventures and kind of projects we're looking for is based on our learnings there. So that's important, and whether the challenging times are now up, 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 is 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 borrow much 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 these 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.

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