Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Executives

Steven Mueller - Chief Executive Officer, President and Director

Greg Kerley - Chief Financial Officer and Executive Vice President

Analysts

Robert Christensen - Buckingham Research Group

Nicholas Pope - Dahlman Rose & Company, LLC

Jason Gammel - Macquarie Research

Dan McSpirit - BMO Capital Markets U.S.

Brian Kuzma - JP Morgan

Michael Scialla - Thomas Weisel Partners Equity Research

David Heikkinen - Tudor, Pickering, Holt

Daniel Guffey

Ronny Eisemann - JP Morgan

Scott Hanold - RBC Capital Markets Corporation

Brian Singer - Goldman Sachs Group Inc.

Jeffrey Hayden - Rodman & Renshaw, LLC

Southwestern Energ (SWN) Q1 2010 Earnings Call April 30, 2010 10:00 AM ET

Operator

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

Steven Mueller

Thank you. Good morning, and thank you for joining us. With me today are Greg Kerley, our CFO and Brad Sylvester, SWN's VP of Investor Relations. If you have not received the copy of yesterday's press release regarding our first 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 uncertainty affecting outcomes, many of which are beyond our control, and are discussed in more detail at the Risk Factors and the Forward-Looking Statement section 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.

We had a very good quarter financially. Our earnings and cash flow growth were outstanding, which highlight the value of our industry-leading low-cost structure. However, while our production grew by 41% during the first quarter, we experienced operational and weather-related field issues in our Fayetteville Shale play, which impacted our production volumes. As a result, 26 fewer wells are placed on production and originally scheduled at March 31, impacting our production first quarter by approximately three Bcf.

We have adjusted our production guidance for the second and third quarters, and remain optimistic that our fourth quarter production guidance is still achievable at this time. Now to talk a bit about each of the operating areas. Earlier this week, our gross operating production in the Fayetteville Shale reached approximately 1.3 Bcf per day, up from about 850 million cubic foot per day, a year ago.

While announcees [ph] and most of the issues are behind us, we did have operational and weather-related field issues, which affected our results during the quarter. Approximately 47% of the wells placed on production during the quarter were the very first well in the section. And 65% of the wells were along and shallower, northern and far eastern borders of the project. Both the first section wells and the shallow well locations were the highest of any quarter in the company's history by at leat 13% and 20%, respectively.

As might be expected, the initial rates from the wells on the edges of our producing area are less than in central and deeper areas, but we continue to improve and achieve initial production results that were better than previous quarter averages for all of these border areas. Weather and challenges encountered in the more remote locations were the first wells in sections, resulting and placing a total of 26 fewer wells on production than what we had originally anticipated, impacting our production by about three Bcf for the quarter.

As we discussed in last call, we have added two additional horizontal drilling rigs during the first quarter and expect to catch up to tour original operated well count by the third quarter of 2010. We're currently running 24 drilling rigs in Fayetteville Shale, 16 that are capable of drilling horizontal wells and eight smaller rigs are used to drill the vertical sections of the wells.

During the first quarter, our horizontal wells had an average completed well cost of $2.8 million per well, average horizontal length of 4,348 feet and average time to drill to total depth of 12 days from re-entry to re-entry. This compares to an average completed well cost of $3 million per well, average horizontal length of 4,303 feet and average time to drill to total depth of 12 days from re-entry to re-entry in the fourth quarter of 2009.

Wells placed on production during the first quarter of 2010 averaged initial production rates of 3.197 million cubic foot per day, down 14% from the average initial production rates of 3,727,000-foot per day in the fourth quarter of 2009. When looking at results through April, we have already placed nearly 50 wells on production, at an average initial production rate of approximately 3.6 million cubic foot per day.

The quarterly decrease in production had one additional factor than the drilling mix or the number of wells in the first walled section. Beginning late 2009, we began what sometimes is called green completions or by wells are placed directly on production very early in the flowback period, so that incremental gas volumes are captured. As a result of the wells being placed on production earlier, the initial pressure the well is flowing against is higher and a recovery of completion fluids is slower. This will capture more gas, but we estimate initial production rates could be reduced by approximately 5% to 10%, depending on the quality of the well.

We continue to test tighter well spacing. And on March 31, we have placed over 375 wells on production the have spacing of 700 feet or less, representing approximately 65-acre spacing or less and have previously concluded that 10 to 12 wells per section is the minimum number of wells needed to efficiently drain the reserves.

The most recent information from this larger group of wells indicates interference of less than 10% compared to earlier estimates of 10% to 15% from the smaller well set. We continue to focus on optimizing the well spacing for the play, and plan to test over 44 different pilots with well spacings that will range from 200 to 450 feet apart, as part of our 2010 drilling program.

To wrap up our discussion of Fayetteville Shale, we are now providing new production date on our zero time production plot of wells with drilled lateral lengths over 5,000 feet as shown in our press release. With over 60 wells included in the sample, we are encouraged by what we're seeing thus far.

In our East Texas operating area, production was 9.6 Bcfe, up from 7.8 Bcfe a year ago. We participated in drilling 11 wells in East Texas during the first quarter, six of which were James Lime, three of which were Haynesville horizontal wells and two of which were Pettet horizontal oil wells.

Initial production rates from the James Lime that were placed on production during the first quarter averaged 6.6 million cubic foot per day, and we placed one well in production from the Haynesville shale during the quarter at an initial production rate of 22.1 million cubic foot per day. Initial production rates in the four(sic) [two] Pettet oil wells that were placed on production during the quarter averaged 292 million barrels of oil with 2.6 million cubic foot of associated gas per day.

In our Conventional Arkoma Program, we participated in three wells and our production from the area was 4.9 Bcf compared to 5.8 Bcfe last year. In Pennsylvania, we have approximately 151,000 net acres in Pennsylvania, prospective for the Marcellus Shale. We're currently drilling our second well for 2010, the Ferguson Keesling 1H[ph] in Bradford County. We plan to compete both wells drilled to date during the second quarter and that should be on production as early as June. At least 15 wells are expected to be drilled by Southwestern in 2010.

In our new ventures program, we announced in March that we have been granted exclusive licenses to search and conduct an exploration program covering over 2.5 million acres in the province of New Brunswick, Canada to test new hydrocarbon basins. As the winner of the bids, our financial commitment over the next three years is approximately $47 million. More than 80% of the work commitment is gathering and processing of geochemical, gravity, magnetic and seismic data. The initial phase of the data gathering is planned to start before the end of 2010.

In closing, natural gas continues to underperform the rest of the commodities. And like all of you, we're carefully watching both the imbalance of supply and demand and the industry's reaction to that imbalance. We have already made some adjustments to our capital allocations to emphasize our best projects. We also remain confident that our low-cost operations, financial strength and flexibility to pursue our drilling program in the Fayetteville Shale give us staying power through the tough times and the ability to add significant value for our shareholders even in the current low gas price environment.

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, our financial results for the quarter were excellent, with earnings at 37% and cash flow, up 12%. Our improved results were driven by our strong production growth and continue to highlight the high quality of our assets and our industry-leading low-cost structure.

We reported earnings for the first quarter of a $172 million, or $0.49 a share, compared to adjusted earnings in the first quarter of 2009 of $125 million, or $0.36 per share, which for comparative purposes exclude a non-cash ceiling test impairment recorded in 2009. We also reported discretionary cash flow of $418 million, up 12% from last year. And we were nearly cash flow neutral for the period, as our cash generated from our operating activities funded 94% of the cash requirements for our capital investments.

Our production totaled 90 Bcf in the first quarter, up 41% from the prior year. And we realized an average gas price of $5.42 in Mcf, down $0.50 per Mcf from the same period last year. Operating income of our E&P segment was $250 million during the quarter, up 39% from the same period last year, excluding the non-cash ceiling test impairment, as the significant growth in our production volumes more than offset the decline in our average realized gas price.

Our commodity hedge position increased our average realized gas price by approximately $0.55 in Mcf in the first quarter. We have approximately 48 Bcf of our remaining 2010 projected natural gas production hedge through fixed price swaps and collars at a weighted average floor price of a little over $8 per Mcf. We recently increased our hedge position in 2011 and also added some hedges in 2012. We hedged an additional 55 Bcf of our 2011 forecasted gas production do cost us collars at a floor price of $5 per Mcf and an average ceiling price of $6.42. And approximately 29 Bcf of our 2012 forecasted gas production at a floor price of $5.50 per Mcf and an average ceiling price of $6.54.

We have one of the lowest cost structures in our industry. And we continue to that trend in the first quarter of this year as our lease operating expenses per unit of production were $0.78 per Mcf during the quarter, unchanged from last year. Our general and administrative expenses per unit of production declined to $0.29 per Mcf in the first quarter, down from $0.31 last year due to our increased production volume.

Taxes other than income taxes were $0.14 per Mcf in the quarter compared to $0.13 in the prior year. Our full cost pool amortization rate also declined, dropping to $1.41 per Mcf in the quarter from $1.82 in the prior year. The decline was due to a combination of our ceiling test impairment recorded in the first quarter of 2009 and our lower trending finding and development costs.

Operating income from our Midstream Services segment increased by 37% in the first quarter to $38 million. The increase was primarily due to increased gathering revenues related to production growth in the Fayetteville Shale play, partially offset by increased operating costs and expenses.

At April 25, our Midstream segment was gathering almost 1.5 billion (sic)[million] cubic feet of gas a day through over 12,000 miles of gathering lines in the Fayetteville Shale play compared to gathering approximately 900 million cubic feet per day a year ago. We invested $474 million during the first quarter of 2010 compared to a little over $500 million in the first quarter of 2009, and drew down our revolver balance by only $20 million during the quarter.

At March 31, we had $345 million borrowed on our $1 billion credit facility, an average interest rate of 1.3%. It had total debt outstanding of a little more than $1 billion. This leaves us with a debt-to-book capital ratio of 29% and a debt-to-market capital ratio of only 7%, which is one of the lowest in our industry.

That concludes my comments. So 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 Jeff Hayden of Rodman & Renshaw.

Jeffrey Hayden - Rodman & Renshaw, LLC

It looks like in the performance in the Fayetteville wells had a nice bump up in April versus what it was in Q1. Just wondering, what were the differences there? Was there a different geographic mix, higher percentage of longer lateral wells? Anything like that going on, which kind of influenced the performance?

Steven Mueller

Before I answer that, let me make one comment. I think Greg said we had 12,000 miles of pipe out there, we only have 1,200 miles. [indiscernible] If anyone asked that question, we don't really have 12,000. But as far as the April wells, there is a little bit different mix in April. We have some rigs drilling on the southern end of our acreage, again current peripheral. But we're that northern and far east are in the 2,500 to 3,000-foot depth range. When you go to the far south, through 6,500 depth range. Two things happen there, you're going to get a little bit better rates down there, but it's going to take a little bit longer to drill it. So while we averaged 12 days to drill wells in the first quarter, and in April, something like 14 days to drill wells, because there are some wells who's also deep or so. There is a little bit of a mix issue. And that just brings up how things have kind of developed over the next few quarters. Both first quarter and second quarter, we will have a significant number of our wells capturing first wells on section. And so there's going to be a different mix from first to second. And there's going to be a different mix compared to last year's and previous quarters we had also. We just going to have to work through that and talk through this as we go through those mixes.

Jeffrey Hayden - Rodman & Renshaw, LLC

And just do kind of a looking at about the potential location you guys have him in the play, how much of it do you think is in kind of the central area and other kind of deeper areas of the play versus how many of your location there in the shallower part of the play right now?

Steven Mueller

Yes, I don't know about the actual mix. I think the best way to do is go look at our website, look at our presentation, and there's a page in there that shows where our Midstreams at. Now that'll tell you what we've tested to date, just where that Midstream infrastructure shows on that map. And you can get a feel for what's been tested today. Then you can kind of look at what need still to be tested. There's a significant amount of new capture that we're going to have to do in the middle of our acreage on the eastern side. And then we've got some of those peripheral capture that we'll do as well. Probably, the best way to give you a feel for the overall mix, our northern acreage is very similar to what Petrohawk has done. They've got a lot of things in the north end. And if you look what their performance has been, you can kind of think about that -- is what our acreage have you there. On the far east, that's where Chesapeake has a lot of their production. You can look at their performance and get a feel for what those wells might do.

Jeffrey Hayden - Rodman & Renshaw, LLC

But did you guys gave any updated expense guidance?

Greg Kerley

As far as LOE or those kind of things, no.

Operator

Our next question is coming from Brian Singer of Goldman and Sachs.(sic) [Goldman Sachs]

Brian Singer - Goldman Sachs Group Inc.

First on the downspacing, can you add any color on, more specifically, what's giving you more confidence in the less than 10% that communication versus your higher levels previously? And talk a little bit about the area or extent of where you see potential better spacing?

Steven Mueller

It really has to do with the number of days we've had the wells on production. When we first made kind of the -- we needed 10 to 12 wells per section call, back in the third quarter of last year. I think the longest we had any wells on were basically 90 to 120 days. Now we've got several much more production, so we've got a better shape on those curves. And so it doesn't look like there's as much interference as we first thought.

Brian Singer - Goldman Sachs Group Inc.

So is that the result then of a much flatter production profile? Or do you -- sounds like you're being conservative earlier and wanted to wait to see more before kind of putting out a 10 percentage or less kind of number?

Steven Mueller

Well, we actually saw in that early part of the performance that 10%-plus. So we did see that. That wasn't being conservative, that was just data, and it's data again today. And part of that -- again the initial mix that we talked about just over 100 wells, and we're talking about 375 wells now. So you're covering a bigger area with those number of wells and getting more information on them. And it looks like you're going to have a higher EUR. In general, when you're talking about the space and unless you're very, very close together in the wells, the IP shouldn't change much. It's all in your EUR estimate. So when we were talking about the fact that we had something greater than 10% and now are less than 10%, it's that EUR and it's that back end of the curve that you're projecting off of that initial production.

Brian Singer - Goldman Sachs Group Inc.

Geographically, are you definitively ruling in anymore areas of your acreage for tighter spacing? I think you'd prefer to solve that more on the south central portion, previously?

Steven Mueller

You mean as far as tighter than the 10 to 12 wells per section?

Brian Singer - Goldman Sachs Group Inc.

Yes, that's right. Or even the 10 to 12 wells per section that are tighter.

Steven Mueller

We're comfortable on average that 10 to 12 is going to work, just about across our entire acreage. We haven't tested everything yet, but what we've tested, we're comfortable with that. With this 44 pilots that we're doing, that will be also be spread across the entire acreage. And let emphasize, we're trying to get 44 pilots done. To do, actually, do the pilots, you need to get 100% participation by all the partners in the well. And so it may end up to be 40 or maybe a couple more than that, but we're doing that right now to get that project. In those cases, we will be testing that tighter spacing. And I fully expect that, ultimately, you're not just going to do 10 to 12 wells across the entire area, you're going to have somewhere that's tighter and some that'll be the 10 to 12.

Brian Singer - Goldman Sachs Group Inc.

Can you just comment on maybe on the operational side of the issues that delayed some of the wells? And are there any risk that, that continues over the next couple of quarters?

Steven Mueller

Well, the simple answer to the second part of your question is risk of it happening. Once you run across the kinds of issues that we have, and I'll describe a little bit of them here in a second, once you run across those issues, you pretty much design the system that you won't get those again. But the real thing and the reason that I put in the letter or put in the press release and put in my comments that I just pointed, is that we're trying to build a system that's robust enough that what we say we can do, we can actually do. And we missed last quarter, and I'm disappointed in that. And so we have to continue to work on building a robust enough system. Now having said that, the kinds of things that happened to us last quarter, some of them were decisions by us. One of the things that happened if you remember back in the third quarter, we have more block pipeline issues. We took some of the rigs that we operated, did maintenance on those. We also took some of those spudder rigs to do the vertical portion of the wells and lay those down. And then whenever the Boardwalk Pipeline issue was resolved, we're going to pick those up. Well, we went to pick them up, it took about 30 days longer to pick them up than we thought. Some of that was them, some of that was us, it just took a little longer. In some cases, it's our pipeline. The reason that we pushed 50 wells already on in April, which is a record for any month, is that we had to lay a 20-mile pipeline. We thought that 20-mile pipeline would be in mid-February. If it's in, in mid-February, we hit our target. We got delayed about 15, 20 days on that pipeline. Part of that was weather, but mostly it was just the number of crossings and the various things we had to do from a surface-permeating standpoint, both with the owners of the surface and with the state and the various agencies. And we lost 20 days. In those kinds of cases, both those ones I described, those are behind us. Those aren't going to happen. But again, it just tells you we're not quite as robust in our system and how we're predicting, and we'll get that fixed.

Operator

Our next question is coming from Joe Allman of JPMorgan.

Ronny Eisemann - JP Morgan

This is actually Ronny Eisemann. Going forward, for the next couple of quarters, do you have a rough estimate of what the mix will be for the percentage of wells drilled in the northern and eastern area?

Steven Mueller

I really don't, at this point. And the reason we don't, we're always trying to work seven or eight months out in advance but, for instance, some of these wells have to go to the hearings. If you don't get the wells and the hearing, it doesn't just affect the one well, but affects everything and it hooks up with those rigs. And so you're always changing the mix and exactly where they're going. So part of -- the best I can say is during the second quarter, we will be doing a significant number of acreage capture. It looks like we did maybe more than we did in the first quarter, but where exactly those are at, I can't tell you the exact mix on that. There'll still be some up in the north and some on the far east. But as I said, we're also drilling some wells on the very southern end of our acreage also.

Ronny Eisemann - JP Morgan

The green completions of the 106 wells brought on in the first quarter, how many of them were green completions?

Steven Mueller

Most of those. And let me just talk quickly about the green completion. Some people call green completion, because you're not releasing some of the gas in the atmosphere, or burning flames on the gas, and so there is some environmental component to it. I think of it a green completion and that's why it's says here some people call it green. It's just economically green for us to do that. We capture about 15 million cubic foot of gas by going directly or very early into the system. That 15 million cubic foot of gas is about $2 an m[ph] to capture that gas. And if you put in perspective, we'll drill 500 wells this year and while 15 million cubic foot doesn't sound like much, that's 7.5 Bcf this year alone of gas that we would've flared that we're going to capture. And that's a significant amount. So the idea was capture that gas. And you might ask why we're not capturing it or whether we didn't captured it before, and that goes back to robust in system. We had to put a special team in place. You have to move a lot of equipment around to do this. And we're just at that stage where we can start doing that part of the process.

Ronny Eisemann - JP Morgan

And of the 122 wells in the fourth quarter, how many of those were green completions?

Steven Mueller

Very few. We started dong this in December.

Ronny Eisemann - JP Morgan

And then, again, the 106 wells brought on in Q1 versus the 50 brought on in April, did the weather delays delay within the quarter, when those wells were brought on? Were they more back-end loaded within the quarter?

Steven Mueller

Yes, and that basically is why we missed our guidance.

Ronny Eisemann - JP Morgan

And with the additional rigs running this year to catch up, is there effect on CapEx?

Steven Mueller

Well, I mentioned we reallocated capital a little bit. We have decisions that we can make about our Fayetteville drilling later in the year. Four of the rigs, actually five of the big rigs of the 1,600 running, we'll be able to make decisions on whether we want to keep those running through the year or not starting in late June and going through November, we can lay down those rigs in various contracts. But what we've done on the capital budget, we've reallocated dollars of Fayetteville Shale. It's economic on any kind of forward curve you're looking at or anything we've got, and we're planning right now to run those rigs through the year. In Pennsylvania, we're a little slow getting the rig to work there. We wanted to get the rig out there the 1st of January, didn't get out there until middle of February. So we've reallocated some of that Pennsylvanian money that's not going to get invested to that Fayetteville Shale. And then we've also backed down a little bit of our new venture dollars, so we can run those rigs through the year in the Fayetteville. So we'd done some minor changes. Overall, that's a total of $50 million to $60 million out of $2.1 billion that we moved around, but the whole idea was get the money working where you've got the best projects at this gas environment.

Operator

Our next question is coming from Michael Scialla of Thomas Weisel Partners.

Michael Scialla - Thomas Weisel Partners Equity Research

Want to ask you about the 5,000-foot laterals, how much are those costing? And what percentage of your acreage do you think you can drill 5,000 feet or more on them, maybe how the economics of those compared to shorter laterals?

Steven Mueller

The 5,000-foot laterals probably earned about to $3.5 million to $3.6 million range today. And that's drilling at basically one well in a section-type number. As you get to a pad, I fully expect that's going to go down a little bit. And let me just also put that in comparison. In the shallow, where we're drilling 4,000- or 35,000-foot laterals, it's only 2,000-foot deep, those are $2.5 million wells. So that's really the range that you got. On the numbers of 5,000-foot laterals, we have -- in the very shallowest portion of the area, probably in the 4,000-foot range. In the far east, we've got a lot more faulting. I don't know if we can quite average 5,000-foot laterals in the far east. But as we look into the future and just look at the geometries, it looks like we're going to have to average better than 5,000, somewhere between 5,000 and 6,000 foot on average across most of our play to, optimally, invest the dollars, to get the most gas out of the ground. So I think a large part of it's going to be 5,000 plus. On the other hand, and you didn't ask the question, but what's the odds of having a bunch of them at 6,000, what's the odds of bunch of 8,000 or 10,000. The real average is somewhere in that 5,000- to 6,000-foot range. We will drill some wells, especially where there's skinny [ph] fault blocks that'll be longer than that. And we've already drilled a couple of wells over 8,000 feet.

Michael Scialla - Thomas Weisel Partners Equity Research

Sounds like from an economic standpoint though, the optimal -- you're kind of zeroing in on this 5,000 to 6,000-foot wells rigs.

Steven Mueller

That's what it looks like today. Let me add, the reason it looks that way, if you try to lay a grid of, say, 10,000-foot laterals. You can put a bunch of 10,000 foot laterals out there but then there's a bunch of we call white space, there's spots on the a map that you can't get to with 10,000 foot laterals. And what you need is a bunch of 2,000 and 2,500 foot laterals to do that, and you end up averaging at 5,000 foot anyway. So when we start looking at it, it looks like that 5,000- to 6,000-foot range for the laterals.

Michael Scialla - Thomas Weisel Partners Equity Research

Any additional acreage you'll need to drill these longer laterals?

Steven Mueller

Well, we've got permission -- there's two things the states work with us on recently. We got permission in December to basically do wells across sections, so that you can drill and the whole sections do the various things under -- there some details in state rules but we can do that administratively now. The one that we're doing it last year, up until December timeframe, we would have to take those well to the commission and get their approval. And now we can just do that as a regular administrative process. The other thing the state's had done for us recently, as we started doing these green completions, we realized that the peak production may not be in the first 10 days and the state's rules were you got to get the top production rate in the first 10 days, top 24 hours in the first 10 days. We now got that, I think it's 45 days, we have to get that to operate. And they changed that back in early January. So those are the two most recent changes to address.

Operator

Our next question is coming from Scott Hanold of RBC Capital Markets.

Scott Hanold - RBC Capital Markets Corporation

So I think you guys kind of covered most of the stuff, but in terms of looking at your spending plan specific on the Fayetteville Shale going forward and I guess what the gas curve looks like right now. You obviously made a case that the well that you're drilling are economic even at these strip prices. How do you think about the full development mode of the Fayetteville and how you hedge that sort of on a go-forward basis?

Steven Mueller

Well, it looks like today that we could have an extended period with relatively low gas prices. And when I say relatively low, is that a high-four or low-five or mid-four but it's probably not six and sevens. We are very economic more doing both Fayetteville Shale and Pennsylvania. And the real thing that's keeping us from going faster or doing something different is more of the cash flow side of the overall equation. First quarter, we only borrowed additional $20 million, so we're real close to cash flow neutral even with the prices we had in the first quarter. And so as we start get cash flow neutral and get some extra dollars, we will put those to work. We're not going to try by ourselves to solve the gas problems that the nation's got. So if we've got economic projects to do at whatever prices out there and we've got the dollars to do it, we can do it in a strong financially situation, we're going to go do it.

Scott Hanold - RBC Capital Markets Corporation

And when you take us through that longer-term picture, is there any consideration of eventually going out there and building your own fit-for-purpose rigs in the Fayetteville based on what you know now, they will be much more optimal than what maybe what you're running at this point?

Steven Mueller

Whether we build them or someone else build them, that will definitely happen. The next rigs we'll add will be built for purpose. We've actually got two of them operating. The rigs we picked up, two of those right now walked, they're AC powered and we're using them on downspacing work, where drilling more wells and one on the pad. The most advance of those rigs are right now averaging less than seven days per well to drill wells on pad work. So there is a big difference between the 12 we're doing right now and that seven. And we'll add rigs, as we add rigs that's exactly the way we'll work it. Now whether we're buying those rigs or someone else's is building them and owning them and supplying to us, we'll make those decisions as the market goes forward in the future.

Scott Hanold - RBC Capital Markets Corporation

Back to the hedging aspect. What is your old plans in terms of what you do on a go-forward basis with hedges? Where do you feel comfortable at luring this in? And the preference for swaps versus colors, so how should we think about your policies going forward?

Steven Mueller

I don't know if there's a swaps versus color preference. But we just in the last week put on some hedges. As Greg said, there are $5 to $5.54 for us in 2011 and 2012. We make a lot of money at $5 or above. And so you'll see us putting on hedges when we can. And we won't hedge obviously our entire production in those years but we'll hedge enough, so that we know we can make good money and head on down the road.

Operator

Our next question is coming from Jason Gammel of Macquarie.

Jason Gammel - Macquarie Research

I wanted to come back and ask a couple more questions about the green completions to make sure I understand the overall effect on the performance of a well. I understand producing into a higher pressure early on is going to have a negative effect on the IP rate. But when we're thinking about ultimate recovery of the well, I understand your capturing incremental gas at the beginning. Are you really doing anything to the ultimate recovery of the well? Is it lowering the decline rate that you see, say, 30 and 60 days out? Any help you can provide on that would be useful.

Steven Mueller

It might -- we're still trying to gather all the data and see -- it might on a 30-day number for instance flatten it out a little bit. I would guess by 60 days, as I said, and one of the reasons the state change the rule to 45 days. Somewhere between 15 and 30 days, you pretty much got all these wells cleaned up the way they should clean up. And at that point, it's no different than when you originally did the well and put it in to the same kind of system, it has the same back pressure off from there, so it performs the same. So EUR is going to be bigger by 15 million cubic foot is basically the answer, and it spread out a little bit different in that first 30 to 45 days. And that's about all there is to it.

Jason Gammel - Macquarie Research

So just as a follow-up then, is a lot of this just essentially the reporting requirements of the state? I mean, it seems to me that the effectiveness of the well is actually improving a little bit even though you stated IP is worst?

Steven Mueller

Yes, we're making money. For those of who follow the IP, it's going to be a little bit down and that's all we want to tell people. It shouldn't affect hardly our 30 day at all, I can say. You might see a little effect -- it shouldn't affect our 60 for sure. So there, that's one of the reasons we have all three columns on the table.

Jason Gammel - Macquarie Research

Just from a tactical standpoint, and I think you've partially answered this, but having such a high percentage of the wells in shallower areas of the play coming under in the quarter, was that simply a function of where you could get the rigs at specific points in time where you have permits? And I think you've already answered this, but what sort of mix would you expect to see moving forward in the shallower sections versus the deeper sections?

Steven Mueller

I did answer the part about the mix, we really don't have a good handle because that's kind of dynamic exactly how much. Certainly, in the second quarter, you're going to see more in the shallow and the far east than you did last year at any point in time. But part of that compares to the first quarter, it will be down a little bit. But is it down 10% or 20%, I don't know. There's a little bit of difference between the quarters. Now I forgot the other part of your question.

Jason Gammel - Macquarie Research

Just from a tactical standpoint, what led you to bring on so many wells in those lower productivity areas?

Steven Mueller

It really had -- we started moving rigs in that direction late last year because number one, we had to capture some acreage. And number two, we wanted to learn more about how we apply some of our current production frac-ing techniques and see how much better wells we could get. And consistently, in the shallow one on Far East areas, we're getting better wells than we had in previous quarters or previous times that we've been out there. And that was key to us to learn that now and also then set us up, so we can go out there and do some of those downspacing tests. You've got to have some wells out there that have a history on them, that are your type wells that you compare against. And we needed to get a recent-type well on those areas and then we'll move out there and do some of that testing. So part of it had to do with getting ready to do downspacing. Part of it had to do is making sure that our techniques we're using could actually get better wells and part of it had to do with acreage capture.

Operator

Our next question is coming from Brian Kuzma with George Weiss.

Brian Kuzma - JP Morgan

I just wanted to make sure I understood. The difference on the 30-day rates from fourth quarter to first quarter, that's mostly due to the mix, that's not due to the green completions?

Steven Mueller

There's a little bit of green completion in the IP but the biggest portion of the IP is mix, yes.

Brian Kuzma - JP Morgan

And I know you don't know exactly what you guys are going to drill this year, but like of your 900,000 acres, you say a 125, 000 were kind of in the Arkoma fairway. How does the rest split out between, like, core, northern and eastern, roughly?

Steven Mueller

On the far western side, we've got about 150,000 acres that's federal unit. That federal unit, there's a couple of wells we drilled a few of years ago, there's a part of a piece of land under federal unit that we can get onto. But there's only a couple of wells that are in that federal unit. We'll drill a couple more wells this year, but there's 156,000 acres there. When you look off to the far east, there's a -- I'm trying to think of how many sections. But there's a couple of hundred sections that we need to get first well on that section on and each section is 640 acres. So that's what's going to be happening over, really the next year and a half to two years far east and some of the southern acreage portions of it. And then as you mentioned, there's that 125,000 acres that's already held by production with our Conventional Arkoma, then 125,000 acres has only a couple of Fayetteville Shale wells on it. And we'll get to that once we get all the acreage captured and we can start working in that direction.

Brian Kuzma - JP Morgan

And then like how much acreage do you think is up north, like the Petrohawk-type well?

Steven Mueller

If you just look at our map, it's across the whole map. If you look at our map, the structure runs basically east to west and gets deeper as you go to the southern side. So the southern side of our acreage is about 6,500 feet. The northern side is about 2,000 feet, so it will just grade from that 2,000 all the way down to 6,500. The dead central portion is 3,500 to 4,000 feet. And I will say that if you look at our maps and any of our presentations, on the eastern side, there's a couple of lakes. We don't have a whole lot of acreage up north of those lakes. That's why we've got a little cut out in our little shaded area we got on that map.

Brian Kuzma - JP Morgan

When I look at your zero time plots that you guys charted here, you guys said that you had 375 wells that are less than 500-foot spacing. Is it fair then to say that there's like 375 wells in the zero-time plot, which are -- have production rates which are 10% lower? You can see what I'm saying there?

Steven Mueller

That would be true, yes, in general.

Brian Kuzma - JP Morgan

And those wells were drilled in the past year?

Steven Mueller

Yes, for the most part. If you're thinking about 2009, we had about 200 acreage castor [ph] wells and we have about 400 wells that we're doing, the 500- to 600-foot spacing. So yes, you're seeing a reflection and you'll see it really in the last -- when you look at those plots, whether it's 3,000 foot or 4000-foot plots, you'll see those in that first 365 days or 180 days turn.

Brian Kuzma - JP Morgan

When I compare like the 4,000-foot curve like the 5,000-foot curve, it doesn't like appear to be linear. I was just curious, it looks like there's some sort of decreasing margin on returns.

Steven Mueller

You mean as far as -- are you talking about linear because at the end there, we got fewer wells that jumps up or linear, how do you say linear?

Brian Kuzma - JP Morgan

I'm sorry, I was referring to like the first 100 days. It looks like there's more recovery per lateral foot on the 4,000-foot. But I didn't know if that was good...

Steven Mueller

That's a pretty parallel, once you get past the very beginning there. So I'd have to see if there actually is more recovery per lateral foot.

Greg Kerley

I am locked to that.

Brian Kuzma - JP Morgan

But help me understand, the 5,000-foot laterals were drilled in the deeper areas, they may have been a bit different, geologically.

Steven Mueller

Not solely deeper areas. They wouldn't be drilled in the very shallowest portions. That basically a couple of miles across the north end of that. But from 3,000-foot or so down to 6,500-foot, they can be drilled anywhere near.

Operator

Our next question is coming from David Heikkinen of Tudor, Pickering, Holt & Company.

David Heikkinen - Tudor, Pickering, Holt

The new venture areas then, obviously, you've talked about Canada and have been continuing to allocate some capital away from there. Is that allocating capital away from leasing or drilling or how should we think about any of the -- how you allocate capital with new ventures?

Steven Mueller

We didn't have any drilling allocated this year for new ventures, what we had this year was leasing and buying data, seismic gravity, magnetics, those kinds of things. What we've done basically is delayed some of the information gathering part of it, some of the seismic data that we're going to get. And some of our leasing, until somebody figures out exactly where we're leasing, we can delay some of that too. So both of those things are going on.

David Heikkinen - Tudor, Pickering, Holt

So it's not that things are getting more competitive and the values are going up, it's just -- that doesn't changing your leasing plans?

Steven Mueller

No, it's not a competitive issue.

David Heikkinen - Tudor, Pickering, Holt

On the Fayetteville, just trying to dissect this a little bit more and thinking about the Petrohawk-type curve in the northern acreage. Can you talk about what you think across your 889,000 acreage? What an average EUR will be for -- you're talking more 5,000-foot laterals now than you used to, where do you think things are going from an average EUR on the Fayetteville?

Steven Mueller

You kind of mixed metaphors there. You have 5,000-foot laterals and average EURs and those kinds of things. What's on our report today is 2.4 Bcf on our PUDs. And we have about 1,200 PUDs on the reserve report. Certainly, you look at the plot, if we average 5,000-foot laterals it would be higher than that. And in general, our best wells as an industry, we've drilled, I think, we're over 10 wells now at 6 million a day IPs. All of those had very high force in the 5,000-foot range. So I think it's just not a perfect extrapolation but those 5,000-foot laterals, as you get a longer lateral, you're going to contacts more rock as long as you frac at the same way. Your EURs are going to go up.

Operator

Our next question is coming from Bob Christensen of Buckingham Research.

Robert Christensen - Buckingham Research Group

Have you guys expressed any kind of interest in the Common Resources? Say, how did you bid, look and what are your impressions of that sale?

Steven Mueller

No comment about whether we bid, looked or did those kinds of things. And as far as impression, my understanding is the closing is in May, and one of the reasons we did not change any capital -- when I talk about a little capital changes, we didn't really change any capital in East Texas. We just needed to get the thing closed, for those who don't know, Common has sold their East Texas portion of their assets. Those East Texas portion, we have 50% of part of that. And I think they sold 29,000 acres, we have 50% of about 20,000 acres, a little less than 20,000. So whenever we have a closing, we need to talk to the new operator and the operator and us meet together and figure out how we're going to develop going forward and figure out their plans. So that's about as much I knew about Common right now.

Robert Christensen - Buckingham Research Group

So you're saying, the drilling capital could be there with new participants perhaps?

Steven Mueller

I just don't know. We're just getting it to closing. Let them get to closing and then we can find out really what they're going to do.

Robert Christensen - Buckingham Research Group

My follow-up is what is your reaction, may be Greg answers as well to some of the joint ventures alliances struck in the Marcellus shale in Pennsylvania as of late?

Greg Kerley

I think there are some interesting numbers that we've seen, that continues to kind of climb up there and definitely several ones of interest. We like our acreage we have in the northeast portion of the play. It's where the shales and some of the thickest areas. And we think that we have at least that kind of value, probably a lot more value in our acreage up there, what we believe we have as we continue to develop it.

Steven Mueller

Let me add that of ways that we would finance or bring in some dollars. JV probably in the Marcellus isn't really high on our list. JV almost anywhere is not real high on our list because there's a lot of operational and a lot of people issues that go with all of that. So while we're kind of interested in what's going on and prices keep going up, which values our acreage higher, we're not really looking for JVs at this point in time. The other side of it, we're not buyers of those prices either. Well, we like what we have. We think we can put our dollars to work better someplace else.

Operator

Next question is coming from Dan McSpirit of BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

Turning to New Brunswick, can you speak to well control in that part of the world. Really what drew you to that part of Canada? Maybe some history of drilling in New Brunswick. And then secondly, can you speak to how it is you plan to dissect the opportunity, given your massive, massive land position, of course, recognizing that it's very, very early innings?

Steven Mueller

In New Brunswick, there's a lot of shallow wells drilled many, many years ago. But there is actually two fields there in the southern part of what's generally called the Maritimes Basin that goes offshore and then comes onshore in New Brunswick. Those two fields is just one gas field, what they know about it today, it's about 200 Bcf but it 's being drilled now. So it could be bigger, it's conventional field. There's another small oil field that was found in the early 1900s. And really those two fields tell you that there's gas and oil in the system. And I need to back up and talk a little bit about how we got into it. We started working on New Brunswick almost a year ago after looking at several different shales in a lot of different places in the U.S. and in Canada. The thought that there might be a Maritimes Basin, a chance for a deeper shale called the Frederick Shale and start doing some work. As we looked at the southern basin that had this oil and gas in it, we were reprocessed a bunch of magnetic data. And as we looked north, it looked to us like there was some basins that could be there that had the depth to basically cooked the Frederick Shale, both for an oil objective, conventionally maybe, oil objective for the shale maybe, gas objectives conventionally and gas objectives for the shale. And the industry really hasn't seen that in the past. The industry's general interpretation as you went north from these producing fields and where these producing fields, there it was, that the basin shale was way up and would be 5,000 further or less in depth. We're seeing things on the magnetics. The magnetics indicate may be as deep as 20,000 or deeper 20,000-foot deeper depths. That's what kind of keyed us into it. And I also tell you a little bit about what we're going to do in the future. What we have to do is confirm that there really are deep enough basins there that we could have the right thermal dynamics to really cooked the rock, the way we want to cook. So what we'll be doing is doing some more gravity magnetic work, that tells you the shape of the basin and gives you a feel for depth of basin. We'll be doing surface geo chem work on the entire area. I think, they're talking about 2,500 stations or something like that over the next year and half. And then we'll lay our seismic program, the ones that figure out where the deeper portions are. We can shoot some seismic and see what the rock looks like in those areas. And then towards the end of that three-year term, we've got one well as a commitment to drill. So over that three-year period of time, we're just going to be to delineating what we think is a basin of and learn as much as we can about it and then drill some wells and figure out it goes from there.

Operator

Our next question is coming from Nicholas Pope of JPMorgan Securities (sic) [Dahlman Rose].

Nicholas Pope - Dahlman Rose & Company, LLC

It's actually Dahlman Rose. Real quick, just curious, you said 15 wells being drilled in Marcellus this year. How many of those you all think you're going to be bringing online during the year?

Steven Mueller

Well, except for the very last ones drilled in December, we should get most of those online during the year. We are currently permitting and laying the short lateral to get to where we're drilling today. All the drillings is going to move within a few miles of the point we're at today. So once that line gets there, we'll be drilling and frac-ing and putting it in that line and go from there.

Nicholas Pope - Dahlman Rose & Company, LLC

And just in terms of capacity to get the gas out of the area, do you have plenty of capacity right now?

Steven Mueller

Yes, we have committed in the past about 20 million a day firm, and then we're committing the other gas right now for the end of this year and then into 2011. We're comfortable we can get the gas out, certainly at the pace we're drilling now.

Operator

Your next question is coming from Daniel Guffey of Thomas Weisel Partners.

Daniel Guffey

You mentioned previously you've drilled some 8,000-foot laterals, I was wondering if you can provide any 30- and 60-day rates? And then also, if you guys have given an EUR or have an internal estimate of EUR for these wells?

Steven Mueller

Well, first off, as I said, the one we've done the 8,000-foot laterals, they've been unique situations where we've drilled in a fault block that you couldn't do two 5,000, there was some characteristic of a fault block that 8,000 made sense. From an IP standpoint, those are fairly high IP, those are going to be 5 million a day type plus IPs. EURs though depends on the fault block and how small the fault block is and those kind of things, whether the EUR matches with that initial rates that you have. I don't know if those are representatives of themselves of what you could do if you were just out in an open area and drilled an 8,000-foot lateral.

Daniel Guffey

So I mean, you mentioned, I guess, there are special situations. So how many 8,000-foot or more laterals do you expect that you'll have? I mean can you even...

Steven Mueller

I don't even know if I can guess that. We've done three or four, we've got three that are in the 8,000-foot range, 7,500 to 8,200 right now. And depending on where you're at, if you're over in the kind of eastern area, you may do one quarter or something over there. If you're over far to the west or central area, you're not going to do very many of them.

Operator

[Operator Instructions] There are no further questions at this time, I'd like to hand the floor back over to Mr. Steve Mueller for any closing comments.

Steven Mueller

Thank you, operator, and thank, all of you for listening to the conference call. There's just two last things I wanted to say. We are disappointed as a company in the quarter because we missed the guidance. And as I said, that tells you something about robustness at operation and we're working on that. We are not at all disappointed in that table. I'll tell you, every once in a while, something will come up and say, well, shall we do the green completions because it may affect the table and that will last about 30 seconds because we look at the economics and say, "Of course, we do that, we'll explain the table as we go through. " And if you look at the table, well, at surface, yes, we have less IP than we had last quarter. That average 3 million a day IP in the areas we're drilling compared to what we would have averaged a year ago in those areas is tremendous. And we're excited about that. And I would just want to make sure that all of you know that we are excited even though the tables look a little different. And then you come back to the way we have discussions, whether we should have that table in there or not in there. And as I said in the past, that table is a learning curve not just for our company but for the entire industry to follow the kinds of things that happen as you drill these kinds of plays out. And it's going to be there forever and we'll be happy to explain as it comes up, whether it's up on one of those numbers or down on one of those numbers as we go through. So I say there are some disappointments, it's a little bit of a disappointment. When you think about it, 41% production increase across the board, better financials than we've had, only borrowed $20 million and had over 3 million a day production rates for the quarter in Fayetteville. We had a great quarter. And with that, I thank you and look forward to the next several quarters.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Southwestern Energ Q1 2010 Earnings Call Transcript
This Transcript
All Transcripts